EX-99.1

Project

Total
Estimated
Capital Costs
($ millions)⁽¹⁾

Expected
In-Service Date

Description

Transportation and Storage

Giles County

In service

Adds 12.9 miles of 8-inch pipeline and other facilities to provide 46,000 Dth/d of new firm service, which is being provided to a third party located off its Line KA system and into Columbia Gas of Virginia’s system

EX-99.1 2 d891954dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

INFORMATION STATEMENT

LOGO

COLUMBIA PIPELINE GROUP, INC.

Common Stock

(Par Value $0.01 Per Share)

NiSource Inc. (“NiSource”) is furnishing this Information Statement to holders of NiSource common stock in connection with the distribution by NiSource of all of the issued and outstanding shares of common stock of Columbia Pipeline Group, Inc. (“CPG”). As of the date of this Information Statement, NiSource owns all of the outstanding common stock of CPG.

NiSource expects that the distribution will be made on July 1, 2015 on a pro rata basis to the holders of record of NiSource common stock as of 5:00 p.m., Central Time, on June 19, 2015, which is the record date. If you are a record holder of NiSource common stock at the designated time on the record date, you will receive one share of CPG common stock for each share of NiSource common stock you hold on that date and time. As discussed under “The Separation,” if you sell your shares of NiSource common stock in the “regular way” market after the record date and prior to the distribution, you will also be selling your right to receive shares of CPG common stock in the distribution. Because CPG shares will only be maintained in book-entry form, you will not receive a stock certificate representing your interest in CPG.

The distribution is expected to be generally tax-free to NiSource, CPG and NiSource stockholders.

You will not be required to make any payment for the shares of CPG common stock that you will receive in the distribution, nor will you be required to surrender or exchange your shares of NiSource common stock or take any other action in order to receive shares of CPG common stock in the distribution. No vote or further action of NiSource stockholders is required in connection with the distribution. We are not asking you for a proxy, and you are requested not to send us a proxy.

There is no current trading market for CPG common stock. However, we expect that a limited market, commonly known as a “when-issued” trading market, for CPG common stock will begin on or about June 17, 2015, and we expect that “regular way” trading of CPG common stock will begin the first trading day following the distribution. We intend to apply to have CPG common stock authorized for listing on the New York Stock Exchange under the symbol “CPGX.”

In reviewing this Information Statement, you should carefully consider the matters described in the section entitled “Risk Factors” beginning on page 31 of this Information Statement.

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved these securities or determined if this Information Statement is truthful or complete. Any representation to the contrary is a criminal offense.

This Information Statement is not an offer to sell, or a solicitation of an offer to buy, any securities.

NiSource first mailed this Information Statement to its stockholders on or about June 19, 2015.

June 2, 2015

TABLE OF CONTENTS


	Page
SUMMARY		2

Overview		2
Our Subsidiaries CEG and the MLP		4
Operating Assets		4
Business Strategies		6
Competitive Strengths		7
System Expansion Opportunities		8
Our Challenges and Risks		11
Our Management		13
Dividends		13
The Separation		14
Payments to NiSource and Its Directors and Executive Officers in Connection with the Separation		14
Questions and Answers about the Separation		15
Summary of the Separation		21

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA		25

RISK FACTORS		31

Risks Relating to Our Business		31
Risks Relating to the Separation		49
Risks Relating to Our Common Stock		55

CAUTIONARY NOTE CONCERNING FORWARD-LOOKING STATEMENTS		59

THE SEPARATION		61

Background		61
Corporate Structure		62
Reasons for the Separation		63
Our Subsidiary the MLP		63
When and How You Will Receive CPG Shares		64
Number of Shares You Will Receive		64
Treatment of Equity-Based Compensation		65
Payments to NiSource and Its Directors and Executive Officers in Connection with the Separation		66
Transferability of Shares You Receive		67
Material U.S. Federal Income Tax Consequences of the Separation		67
Market for Our Common Stock		69
Trading of Common Stock after the Record Date and Prior to the Distribution		70
Results of the Separation		70
Conditions to the Distribution		71
Dividends		72
Reasons for Furnishing This Information Statement		72

CAPITALIZATION		73

BUSINESS		74

Overview		74
Business Strategies		75
Competitive Strengths		75
Our Subsidiary the MLP		76
Our Operations and Operating Assets		77

TABLE OF CONTENTS—(Continued)


	Page
FERC Regulation		91
Seasonality		93
Environmental and Occupational Health and Safety Regulation		93
Pipeline Safety and Maintenance		98
Title to Properties		100
Insurance		100
Facilities		100
Employees		100
Legal Proceedings		100

MANAGEMENT		101

Executive Officers Following the Separation		101
Our Board of Directors Following the Separation and Director Independence		103
Board Leadership Structure and Risk Oversight		106
Committees of Our Board of Directors		106
Code of Business Conduct		109
Corporate Governance Guidelines		109
Director Compensation		109

COMPENSATION DISCUSSION AND ANALYSIS		111

Introduction		111
CPG’s Compensation Executive Compensation Philosophy and Programs Following the Separation		111
Overview of the 2014 Executive Compensation Program		112
Executive Compensation Highlights		112
Executive Compensation Philosophy		113
Principal Elements of 2014 Compensation Program		114
Other Compensation and Benefits		115
Executive Compensation Process		117
Actions Related to 2014 Compensation		118
Anticipated Compensation Programs Following the Separation		126

COLUMBIA PIPELINE GROUP, INC. 2015 OMNIBUS INCENTIVE PLAN		127

Plan Term		127
Administration		127
Eligible Participants		127
Number of Shares and Limitations		128
Types of Awards		128
Performance Targets		130
Duration, Adjustments, Modifications, Terminations		131
New Plan Benefits		131

COMPENSATION OF EXECUTIVE OFFICERS		132

SECURITY OWNERSHIP OF MANAGEMENT, DIRECTORS AND PRINCIPAL STOCKHOLDERS		146

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		149

Policies and Procedures with Respect to Transactions with Related Persons		149
Agreements with NiSource Relating to the Separation		149
Other Agreements with NiSource		154

TABLE OF CONTENTS—(Continued)


	Page
DESCRIPTION OF CAPITAL STOCK		155

Overview		155
Authorized Capital Stock		155
Common Stock		155
Preferred Stock		156
Certain Provisions of Delaware Law, Our Charter and Our Bylaws		156
Limitation of Liability of Directors		158
Choice of Forum		159
Indemnification of Directors and Officers		159
Transfer Agent and Registrar		159
NYSE Listing		159

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA		160

MLP Adjustments		160
Distribution Adjustment		160
Financing Adjustments		160
Other Adjustments		161
Non-GAAP Financial Measures		164

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		166

Separation		166
Overview		166
Our Subsidiary the MLP		166
Operating Assets		167
Factors and Trends That Impact Our Business		168
How We Evaluate Our Operations		172
Items Affecting Comparability of Our Financial Results		174
General Trends and Outlook		175
Results of Our Operations		176
Liquidity and Capital Resources		179
Critical Accounting Policies		185
Recently Issued Accounting Pronouncements		187
Qualitative and Quantitative Disclosures About Market Risk		188
Off-Balance Sheet Arrangements		188

WHERE YOU CAN FIND MORE INFORMATION		189

HOUSEHOLDING		189

INDEX TO FINANCIAL STATEMENTS		F-1

iii

NOTE REGARDING DEFINED TERMS

We use the following terms throughout this Information Statement (the “Information Statement”):

“We,” “us,” “our,” the “Company” and “CPG” refer to Columbia Pipeline Group, Inc., a Delaware corporation, and its consolidated subsidiaries including CEG and the MLP (as each is defined below), unless the context otherwise requires, which at the time of the Distribution (as defined below) will hold the assets and liabilities associated with the natural gas transmission pipeline, midstream and storage business of NiSource (as defined below).

“CEG” refers to Columbia Energy Group, a Delaware corporation, and its consolidated subsidiaries.

“Columbia OpCo” refers to CPG OpCo LP, a Delaware limited partnership, and its consolidated subsidiaries.

“Distribution” refers to the distribution of all of the shares of our common stock owned by NiSource to stockholders of NiSource as of the Record Date (as defined below).

“Distribution Date” means the date on which the Distribution occurs.

“MLP” refers to Columbia Pipeline Partners LP, a Delaware master limited partnership, and its consolidated subsidiaries.

“NiSource” refers to NiSource Inc., a Delaware corporation, and its consolidated subsidiaries (other than CPG and its consolidated subsidiaries), unless the context otherwise requires.

“Record Date” means 5:00 p.m. Central Time on June 19, 2015.

“Separation” refers to the spin-off of the natural gas transmission pipeline, midstream and storage business from NiSource. The Separation will be effectuated through a pro rata distribution of shares of our common stock to NiSource stockholders as of the Record Date.

INDUSTRY AND MARKET DATA

The market and statistical data included in this Information Statement regarding the natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations, commissioned reports and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this Information Statement, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this Information Statement or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Cautionary Note Concerning Forward-Looking Statements” and “Risk Factors” in this Information Statement.

SUMMARY

This summary highlights selected information contained elsewhere in this Information Statement and provides an overview of our company, our separation from NiSource (as defined below) and the distribution of our common stock by NiSource to its stockholders, which is the means by which the separation will be effected. For a more complete understanding of our business and the separation and distribution, you should read the entire Information Statement carefully, particularly the discussions set forth under “Risk Factors,” “Cautionary Note Concerning Forward-Looking Statements” and our audited consolidated and combined financial statements and notes to those statements appearing elsewhere in this Information Statement.

Unless the context otherwise requires, references in this Information Statement to (i) “CPG,” the “Company,” “we,” “our” or “us” refer to Columbia Pipeline Group, Inc. and its consolidated subsidiaries, after giving effect to the separation and distribution, (ii) “NiSource” refers to NiSource Inc. and its consolidated subsidiaries, (iii) “CEG” refers to Columbia Energy Group and its consolidated subsidiaries, (iv) “MLP” refers to Columbia Pipeline Partners LP and its consolidated subsidiaries, and (v) “Columbia OpCo” refers to CPG OpCo LP and its consolidated subsidiaries. The overall transaction in which we will be separated from NiSource is sometimes referred to in this Information Statement as the “Separation.” The transaction in which NiSource will distribute to its stockholders all of the shares of our common stock is referred to in this Information Statement as the “Distribution.”

Columbia Pipeline Group, Inc.

Overview

We are a growth-oriented Delaware corporation formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets.

We own approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 million dekatherms (represented as “MMDth” or in a measure of “Dth” for dekatherms less than 1 MMDth) of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2014, 94% of our revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years. We own these assets through Columbia OpCo, a partnership between our wholly owned subsidiary CEG and the MLP.

Through our wholly owned subsidiary CEG, we own the general partner of the MLP, all of the MLP’s incentive distribution rights and all of the MLP’s subordinated units, which, in the aggregate, represent a 46.5% limited partnership interest in the MLP. The MLP completed its initial public offering on February 11, 2015, selling 53.5% of its limited partnership interests.

We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $5.0 billion for identified projects that we expect will be completed by the end of 2018. We plan that a portion of these costs will be financed through issuances of additional limited partnership interests in the MLP. Please read “—System Expansion Opportunities” for additional information about our growth opportunities.

The following is a simplified diagram of our ownership structure, including key operating subsidiaries immediately following the Separation:

LOGO

Our Subsidiaries CEG and the MLP

CEG was originally formed as a Delaware corporation in 1926 and, since its acquisition by NiSource in 2000, has owned and operated substantially all of the natural gas transmission and storage assets of NiSource. CEG’s Columbia Pipeline Group has achieved a brand name in the energy infrastructure industry and developed strong relationships with producers, marketers and other end-users of natural gas throughout the upstream and midstream industries. In addition, over the past five years, CEG has implemented internal expansion capital projects totaling over $1.8 billion. We intend to utilize the significant experience of CEG’s management team to execute our growth strategy, including the construction, development and integration of additional energy infrastructure assets. We own 100% of CEG.

The MLP is a fee-based, growth-oriented Delaware limited partnership formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets. The business and operations of the MLP are conducted through Columbia OpCo, a partnership between CEG and the MLP. The MLP owns the general partner of Columbia OpCo. Through our wholly owned subsidiary CEG, we own the general partner of the MLP, all of the MLP’s incentive distribution rights and all of the MLP’s subordinated units, which, in the aggregate, represent a 46.5% limited partnership interest in the MLP. The MLP completed its initial public offering on February 11, 2015, selling 53.5% of its limited partnership interests.

CEG is required to offer the MLP the right to purchase its 84.3% limited partnership interest in Columbia OpCo before it can sell that interest to anyone else. Although the MLP has the right of first offer to purchase CEG’s interest in Columbia OpCo, the MLP is not obligated to purchase any additional interest in Columbia OpCo from CEG.

Operating Assets

Interstate Pipeline and Storage Assets. We own the following natural gas transportation and storage assets, which are regulated by the Federal Energy Regulatory Commission (the “FERC”):

•

Columbia Gas Transmission, LLC (“Columbia Gas Transmission”). We own 100% of the ownership interests in Columbia Gas Transmission, which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shale areas and other producing basins to the Midwest, mid-Atlantic and northeast regions. The system consists of approximately 11,400 miles of natural gas transmission pipeline, 89 compressor stations with 635,671 horsepower of installed capacity and approximately 3,436 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

•

Columbia Gulf Transmission, LLC (“Columbia Gulf”). We own 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with approximately 3,300 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus and Utica shale areas, Columbia Gulf has executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. As a result, once these projects are completed, the system will be able to receive Marcellus and Utica supplies, through upstream pipelines such as Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including liquefied natural gas (“LNG”) export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

•

Millennium Pipeline Joint Venture (“Millennium Pipeline”). We own a 47.5% ownership interest in Millennium Pipeline Company, L.L.C., which transports an average of 1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline, and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

•

Hardy Storage Joint Venture (“Hardy Storage”). We own a 50% ownership interest in Hardy Storage Company, LLC, which owns an underground natural gas storage field in the Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth and the ability to deliver 176,000 Dth/d. A third party, Piedmont Natural Gas Company, Inc., owns the remaining 50% ownership interest in Hardy Storage.

•

Crossroads Pipeline Company (“Crossroads”). We own 100% of the ownership interests in Crossroads, which is a 202-mile interstate natural gas pipeline operating in Indiana and Ohio. Crossroads has multiple interconnects including: Natural Gas Pipeline Company of America, Trunkline Gas Company, Vector Pipeline and Panhandle Eastern that allow it to access mid-continent, Rocky Mountain, Gulf Coast, Permian and Canadian supplies. Crossroads accesses markets in Indiana, Illinois, Michigan and Ohio.

Gathering, Processing and Other Assets. We own the following gathering, processing and other assets:

•

Columbia Midstream Group, LLC (“Columbia Midstream”). We own 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 103 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale areas.

•

Pennant Midstream, LLC (“Pennant”). We own a 50% ownership interest in Pennant, which owns approximately 80 miles of wet natural gas gathering pipeline infrastructure, a gas processing facility and a natural gas liquids (“NGLs”) pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp Energy Company (“Hilcorp”) jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

•

Columbia Energy Ventures, LLC (“CEVCO”) and Other. We own 100% of the ownership interests in CEVCO, which manages Columbia OpCo’s mineral rights positions in the Marcellus and Utica shale areas. CEVCO owns production rights to approximately 460,000 acres and has subleased the production rights in four storage fields and has also contributed its production rights in one other field. In addition, we own 100% of the ownership interests in CNS Microwave, Inc. (“CNS Microwave”), which provides ancillary communication services to us and third parties.

The following table sets forth selected data for our primary assets as of December 31, 2014:


	Miles of Pipeline		Total Annual Throughput (MMDth)		% of Transportation Revenue Generated Under Firm Contracts			Weighted Average Remaining Contract Life (years)
Pipeline Assets:
Columbia Gas Transmission		11,400		1,379.4		99	%		5.5
Columbia Gulf		3,300		626.7		95	%		4.3
Millennium Pipeline⁽¹⁾		253		470.9		98	%		5.7


	Working Storage Capacity (MMDth)		Total Annual Withdrawal (MMDth)		Total Annual Injection (MMDth)		% of Storage Revenue Generated Under Firm Contracts			Weighted Average Remaining Contract Life (years)
Storage Assets:
Columbia Gas Transmission		287		217		238.4		100	%		3.0
Hardy Storage⁽¹⁾		12		9.8		11.3		100	%		8.3


	Miles of Pipeline		Processing Capacity (MMcf/d)		% of Transportation Revenue Generated Under Firm Contracts			Weighted Average Remaining Contract Life (years)
Gathering & Processing:
Columbia Midstream		103		N/A		100	%		7.8
Pennant⁽¹⁾		80		200		100	%		9.5

(1)	Table data represents 100% of the assets shown. We own a 47.5%, 50% and 50% ownership interest, respectively, in Millennium Pipeline, Hardy Storage and Pennant.

Business Strategies

Our principal business objective is to utilize our existing geographic advantages, flexible capital structure, management strength and diverse customer base to substantially increase our fee-generating long-term assets, positioning us to pay dividends to our stockholders and increase such payments over time. We expect to achieve this objective through the following business strategies:

Capitalize on organic expansion opportunities. Our assets are strategically located within close proximity to growing production from the Marcellus and Utica shale areas and growing demand centers, providing us with substantial organic expansion opportunities. We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include estimated capital costs of approximately $5.0 billion for identified projects that we expect will be completed by the end of 2018. We intend to leverage our management team’s expertise in constructing, developing and optimizing our assets in order to increase and diversify our customer base, increase natural gas supply on our system and maximize volume throughput.

billion in estimated capital costs for organic growth projects that we expect will be completed by the end of 2018, and we expect that the MLP will exercise its preemptive right to purchase these newly issued equity interests to the extent financing is available. The MLP also has a right of first offer with respect to acquiring CEG’s retained 84.3% limited partnership interest in Columbia OpCo if CEG decides to sell such interest. We do not expect to sell CEG’s retained limited partnership interest in Columbia OpCo in the near term.

Maintain and grow stable cash flows supported by long-term, fee-based contracts. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio to minimize our direct commodity price exposure. We will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications. Substantially all of the $5.0 billion in estimated capital costs for organic growth projects that we expect to complete by the end of 2018 are supported by long-term service contracts and binding precedent agreements.

Target a conservative and flexible capital structure. We intend to target credit metrics consistent with the profile of investment-grade midstream energy companies. Furthermore, we intend to maintain a balanced capital structure while financing the capital required to (i) contribute substantially all of the capital required to finance our organic expansion projects and (ii) pursue potential third-party acquisitions.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

Strategically located assets. As a result of the geographic location of our operations, we are uniquely positioned to capitalize on both the growing natural gas production volumes in the Marcellus and Utica shale areas and the increasing demand for transportation, storage and related midstream services from new and existing customers. In addition, our assets provide a unique footprint from the Marcellus/Utica region to the Gulf of Mexico, where the majority of the natural gas liquefaction facilities for LNG export have been announced, positioning us to capitalize on the growing LNG export market.

Integrated service offerings, providing increased revenue opportunities. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, processing, compression, transportation and storage. Our ability to move producers’ natural gas and NGLs from the wellhead to market allows us to earn revenue from multiple services related to a single supply of natural gas and take advantage of incremental revenue opportunities that present themselves along the value chain. Providing multiple services benefits us in attracting new customers while providing us with a better understanding of each customer’s needs and the marketplace. In addition, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers’ demand for natural gas. We believe the integrated nature of our operations and the broad range of services we provide to customers allows us to compete effectively with other pipeline, storage and midstream companies that operate in our marketplace.

Stable and predictable cash flows. We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices. For the year ended December 31, 2014, approximately 94% of our revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years. Furthermore, a significant portion of our cash flows are generated from contracts with creditworthy customers including local distribution companies (“LDCs”), municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters.

Financial flexibility to pursue growth opportunities. At the time of the Separation, we expect to hold an investment-grade credit rating on CPG’s long-term debt and maintain sufficient cash and liquidity to allow us to invest in high-return projects. CPG has entered into a $1,500 million credit facility which will be effective upon the Separation, of which a minimum of $750 million will be dedicated as credit support for Columbia OpCo and its subsidiaries in connection with a money pool arrangement. The remainder of the credit facility will be available as an additional source of financing to pursue our growth opportunities. In addition, the MLP has a $500 million credit facility. We also expect that over time, the MLP will raise additional capital through issuances of additional limited partnership interests. These various sources of financing should enable us to fund our organic capital investment projects and third-party acquisitions as needed.

Experienced management team with a proven record of asset operation, construction, development and integration expertise. Our management team has an average of approximately 25 years of experience in the energy industry and a proven record of successfully managing, operating, developing, building, acquiring and integrating transportation, storage and other midstream assets. Our management team has established strong relationships with producers, marketers, LDCs and other end-users of natural gas throughout the upstream and midstream industries, which we believe will be beneficial to us in pursuing organic expansion opportunities. Our management team is also committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We believe our management team provides us with a strong foundation for evaluating growth opportunities and maintaining the integrity and efficiency of our assets and operations.

System Expansion Opportunities

According to an ICF International study from June 2014, aggregate gas production from the Marcellus and Utica shale areas is projected to grow to 34 MMDth/d by 2035. Our pipelines have already begun to experience increased throughput associated with the recent increase in production from the Marcellus and Utica shale areas. Substantially all of Columbia Gas Transmission’s expansion projects are supported by long-term firm transportation agreements providing for the transportation of natural gas primarily from the Marcellus and Utica shale areas totaling over 2.75 MMDth/d of capacity. In addition, Columbia Gulf, acting as a conduit to transport Marcellus and Utica shale gas, as well as gas from other supply basins to southern markets and LNG terminals, has entered into binding precedent agreements for approximately 2.3 MMDth/d of capacity. Certain of these projects are subject to limited conditions precedent. The unique location and capabilities of our pipeline assets place us in a strategically advantageous position to continue to capitalize on expected growth in production from the Marcellus and Utica shale areas.

To further capitalize on these and other positive trends, we are pursuing the following significant projects, which have either recently been placed in service or will be placed in service over the next several years:


Project	Total Estimated Capital Costs ($ millions)⁽¹⁾	Expected In-Service Date	Description

Line 1570 Expansion	18	In service	Replaces approximately 19 miles of 20-inch pipeline with 24-inch pipeline and adds two compressors to increase capacity by 99,000 Dth/d

West Side Expansion (Columbia Gas Transmission)	87	In service	Increases supply takeaway from the Marcellus shale to Leach with piping modifications and compression to add 444,000 Dth/d of capacity

West Side Expansion (Columbia Gulf—Bi-Directional)⁽²⁾	113	Third quarter 2015	Adds compressor station modifications along Line 100, replaces horsepower of 30,750 at Alexandria, and enhances existing interconnects to provide 540,000 Dth/d of takeaway capacity from Leach, which accesses various Gulf Coast markets

Chesapeake LNG	33	Second quarter 2015	Replaces existing LNG peak shaving facilities for 120,000 Dth/d of peak deliverability

East Side Expansion	275	Fourth quarter 2015	Expands facilities along Line 1278 to transport Marcellus production to mid-Atlantic markets with 312,000 Dth/d of additional capacity

Kentucky Power Plant	24	Second quarter 2016	Adds 2.7 miles of 16-inch greenfield pipeline from Columbia Gas Transmission’s Line P to a third-party power plant, and other related facilities to provide 72,000 Dth/d of new capacity

Utica Access	51	Fourth quarter 2016	Adds 4.7 miles of 20-inch pipeline and bi-directional launchers and receivers to deliver up to 205,000 Dth/d of Utica supply to Columbia Gas Transmission’s highly liquid trading pool, commonly referred to as the “TCO Pool”


Project	Total Estimated Capital Costs ($ millions)⁽¹⁾	Expected In-Service Date	Description

Leach XPress	1,420	Fourth quarter 2017	Installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system; 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system; and approximately 101,700 horsepower across multiple sites to provide approximately 1.5 MMDth/d of capacity out of the Marcellus and Utica production regions to the Leach compressor station (“Leach CS”) located on the Columbia Gulf system, TCO Pool, and other markets on Columbia Gas Transmission system

Rayne XPress	383	Fourth quarter 2017	Across three major phases, Columbia Gulf will complete compressor station modifications along the mainline from the Rayne compressor station (“Rayne CS”) located on the Columbia Gulf system to Leach CS, replacement of 27,000 horsepower at Rayne CS, and add two greenfield compressor stations totaling 35,000 horsepower to create over 1 MMDth/d of southbound capacity away from Texas Eastern Transmission and Columbia Gas Transmission receipts

Cameron Access	310	First quarter 2018	Adds a new 26-mile 36-inch pipeline; a new compressor station; and enhances existing compression to create 800,000 Dth/d of additional capacity into the Cameron LNG terminal

WB XPress	850	Fourth quarter 2018	Transports approximately 1.3 MMDth/d of Marcellus shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which includes access to the Cove Point LNG terminal


Project	Total Estimated Capital Costs ($ millions)⁽¹⁾		Expected In-Service Date	Description
Gathering and Processing

Washington County Gathering		120	2015—2018	Constructs a field gathering system with compression to feed natural gas into Line 1570

Big Pine Expansion		65	Third quarter 2015	Nine miles of 20-inch pipeline extension, up to 6,000 horsepower compression in the western Pennsylvania shale production region
Modernization

Modernization Program		1,200	Continuing through October 2017	Various system enhancements to address reliability and integrity pursuant to Columbia Gas Transmission modernization settlement; please read “Business—Our Operations and Operating Assets—Columbia Gas Transmission—Tariff Rates”
Total	$	4,974

(1)	Represents the project cost expected to be incurred prior to the in service date.

(2)	We expect the Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) to be placed in service in the third quarter of 2015.

These projects are subject to risks, including unexpected costs or delays. For more information about our system expansion projects, please read “Business—Our Operations and Operating Assets” and “Risk Factors—Risks Relating to Our Business.”

Our Challenges and Risks

We are subject to numerous risks as more fully described in the section of this Information Statement entitled “Risk Factors.” The challenges and risks we face in implementing our business strategies include the following:

Risks Relating to Our Business

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses to enable us to pay dividends to our stockholders.

•

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to pay dividends to our stockholders.

•

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.

•

Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.

•

Columbia OpCo is a restricted subsidiary and a guarantor under our credit facilities and, if requested by us, will guarantee our future indebtedness. In addition, CPG is a guarantor under the MLP’s credit facility. Such indebtedness could limit Columbia OpCo’s and CPG’s ability to take certain actions, including incurring additional indebtedness, making acquisitions and capital expenditures and, in the case of Columbia OpCo, making distributions to CPG, which could adversely affect our business, financial condition, results of operations, ability to pay dividends to our stockholders and value of our common stock.

•

Debt that we incur in the future may limit our flexibility to obtain additional financing and to pursue other business opportunities.

•

Restrictions under our new or any future credit facilities could adversely affect our business, financial condition, results of operations and ability to pay dividends to our stockholders.

•

There can be no assurance that we will be able to access the capital markets to raise debt or equity financing on acceptable terms.

•

If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations.

•

Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.

Risks Relating to the Separation

•

If the Distribution were to fail to qualify as tax-free for U.S. federal income tax purposes, then we, NiSource and our stockholders could be subject to significant tax liability, and we could be required to indemnify NiSource for all or a portion of such liability.

•

We may be unable to achieve some or all of the benefits that we expect to achieve as an independent, publicly traded company.

•

We have no operating history as an independent, publicly traded company, and our historical and pro forma financial statements are not necessarily representative of the results we would have achieved as an independent, publicly traded company and may not be reliable indicators of our future results.

•

We might not be able to engage in desirable strategic transactions and equity issuances following the Distribution because of certain restrictions relating to requirements for tax-free distributions.

•

Following the Separation, for a period of time, we will continue to depend on NiSource to provide us with certain services for our business. The services that NiSource will provide to us following the Separation may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with NiSource expire.

Risks Relating to Our Common Stock

•

There is no existing market for our common stock, and a trading market that will provide you with adequate liquidity may not develop for our common stock. In addition, once our common stock begins trading, the market price of our shares may fluctuate significantly.

•

Substantial sales of our common stock may occur in connection with the Distribution, which could cause our stock price to decline.

•

The future payment of dividends will be at the sole discretion of our board of directors and will be dependent on several factors. We cannot guarantee the timing, amount or payment of dividends.

•

Provisions of Delaware law and our charter documents may delay or prevent an acquisition of us that stockholders may consider favorable or may prevent efforts by our stockholders to change our directors or our management, which could decrease the value of your shares.

Our Management

At the time of the Separation, the following individuals are expected to serve as our executive officers:


Name		Position
Robert C. Skaggs, Jr.		Chief Executive Officer
Stephen P. Smith		Executive Vice President and Chief Financial Officer
Glen L. Kettering		President
Stanley G. Chapman, III		Executive Vice President and Chief Commercial Officer
Shawn L. Patterson		Executive Vice President and Chief Operations Officer
Brett A. Stovern		Executive Vice President and Chief Operating Officer for Columbia Midstream
Karl Brack		Senior Vice President of Human Resources and Employee Engagement
Robert E. Smith		General Counsel, Senior Vice President and Corporate Secretary
Jon D. Veurink		Senior Vice President and Chief Accounting Officer

The following individuals are expected to serve on our board of directors following the Separation:


Name		Position
Robert C. Skaggs, Jr.		Chairman of the Board
Sigmund L. Cornelius		Director
Marty R. Kittrell		Director
W. Lee Nutter		Director
Deborah S. Parker		Director
Lester P. Silverman		Director
Teresa A. Taylor		Director

For more information about our executive officers and directors, please read “Management.”

Dividends

requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend in the future, there can be no assurance that we will continue to pay such dividends or the amount of such dividends.

The Separation

NiSource’s board of directors believes that separating our businesses from the remainder of NiSource’s businesses is in the best interests of NiSource and its stockholders for a number of reasons, including:

•

Enhanced strategic and management focus—The Separation will allow each company to more effectively pursue its own distinct operating priorities and strategies and will enable the management of both companies to pursue separate opportunities for long-term growth and profitability and to recruit, retain and motivate employees pursuant to compensation policies that are appropriate for their respective lines of business;

•

More efficient allocation of capital—The Separation will permit each company to concentrate its financial resources solely on its own operations, providing greater flexibility to invest capital in its business in a time and manner appropriate for its distinct strategy and business needs, all of which will facilitate a more efficient allocation of capital;

•

Direct investment identity—NiSource’s board of directors believes that NiSource’s businesses and our businesses appeal to different types of investors with different industry focuses, investment goals and risk profiles. NiSource and CPG have different investment and business characteristics, including different opportunities for growth, capital structures, business models and financial returns. The Separation will enable investors to evaluate the merits, performance and future prospects of each company’s businesses and to invest in each company separately based on these distinct characteristics; and

•

Independent equity structure—The Separation will create an independent equity structure that will afford CPG direct access to capital markets and will facilitate the ability to capitalize on its unique growth opportunities and effect future acquisitions utilizing, among other types of consideration, shares of its common stock. Furthermore, an independent structure should enable each company to provide equity incentive compensation arrangements for its key employees that are directly related to the market performance of each company’s common stock. NiSource’s board of directors believes such equity-based compensation arrangements should provide enhanced incentives for performance and improve the ability for each company to attract, retain and motivate qualified personnel.

In evaluating the Separation, the NiSource board of directors also considered a number of potentially negative factors. The NiSource board of directors concluded that the potential benefits of the Separation outweighed these factors. Neither NiSource nor CPG can assure you that, following the Separation, any of the benefits described above or otherwise will be realized to the extent anticipated or at all.

Payments to NiSource and Its Directors and Executive Officers in Connection with the Separation

For a description of the payments to NiSource and its directors and executive officers in connection with the Separation, see “The Separation—Payments to NiSource and Its Directors and Executive Officers in Connection with the Separation” beginning on page 66 of this Information Statement.

Questions and Answers about the Separation

The following is only a summary of the terms of the Separation. You should read the section entitled “The Separation” beginning on page 61 of this Information Statement for a more detailed description of the matters described below.

Q:	What is the Separation?

A:	The Separation is the spin-off of our business from NiSource. Once the Separation is complete, we will be an independent, publicly traded company. NiSource will continue as an independent, publicly traded company focused on its natural gas and electric utility business.

Q:	What is the Distribution?

The Distribution is the method by which NiSource will effectuate the Separation. In the Distribution, NiSource will distribute to its stockholders all of the shares of our common stock that it owns. Following the Distribution, CPG will be an independent, publicly traded company, and NiSource will not retain any ownership interest in CPG. The number of shares of NiSource common stock you own will not change as a result of the Distribution.

Q:	Why is NiSource separating CPG from NiSource?

NiSource’s board of directors and management believe that the Separation will provide, for each of NiSource and CPG following the Separation, enhanced strategic and management focus, more efficient allocation of capital, direct investment identity and an independent equity structure. These benefits are more fully described under the caption “The Separation—Reasons for the Separation” beginning on page 63 of this Information Statement.

Q:	Why is the separation of the two companies structured as a distribution?

A:	NiSource believes that a distribution of our shares is the most efficient way to separate CPG in a manner that is intended to enhance long-term value for NiSource stockholders.

Q:	What will I receive in the Distribution?

As a holder of NiSource common stock, you will receive a dividend of one share of our common stock for each share of NiSource common stock you hold on the Record Date (as defined below). Your proportionate interest in NiSource will not change as a result of the Distribution. For a more detailed description, see “The Separation” beginning on page 61 of this Information Statement.

Q:	What is the record date for the Distribution, and when will the Distribution occur?

The Record Date is 5:00 p.m., Central Time, on June 19, 2015. We expect that Computershare Trust Company, N.A. (the “Distribution Agent”) will act as distribution agent and will distribute to NiSource stockholders the shares of our common stock on July 1, 2015, which we refer to as the Distribution Date.

Q:	What will be distributed in the Distribution?

Approximately 317,535,860 shares of our common stock will be distributed in the Distribution, based on the number of shares of NiSource common stock outstanding as of May 28, 2015. The actual number of shares of our common stock to be distributed will be calculated on the Record Date. The shares of our common stock to be distributed by NiSource will constitute all of the shares of our common stock issued and outstanding immediately prior to the Distribution.

Q:	What are the conditions to the Distribution?

The Distribution is subject to a number of conditions, including, among others, (1) the receipt by NiSource of an opinion of its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution for U.S. federal income tax purposes under Section 355 of the Internal Revenue Code of 1986, as amended (the “Code”), (2) the SEC declaring effective the registration statement of which this Information Statement forms a part and (3) final approval of the Distribution by the board of directors of NiSource. However, even if all of the conditions have been satisfied, NiSource may terminate and abandon the Distribution and the related transactions at any time prior to the Distribution Date. For a more detailed description, see “The Separation—Conditions to the Distribution” beginning on page 71 of this Information Statement.

Q:	Can NiSource decide to cancel the Distribution even if all of the conditions have been satisfied?

Yes. The board of directors of NiSource may, in its sole discretion and at any time prior to the Distribution Date, terminate the Distribution, even if all of the conditions to the Distribution have been satisfied. For a more detailed description, see “The Separation—Conditions to the Distribution” beginning on page 71 of this Information Statement.

Q:	What do I have to do to participate in the Distribution?

No action is required on your part, but we urge you to read this document carefully. Stockholders who hold NiSource common stock as of the Record Date will not be required to pay any cash or deliver any other consideration, including any shares of NiSource common stock, to receive the shares of our common stock distributable to them in the Distribution. In addition, no stockholder approval of the Distribution is required or sought. We are not asking you for a vote and are not requesting that you send a proxy card.

Q:	How will NiSource distribute shares of CPG common stock?

If you are a registered stockholder (meaning you own your stock directly through an account with NiSource’s transfer agent, Computershare Trust Company, N.A. (“Computershare” or the “Transfer Agent”), Computershare will mail you a book-entry account statement that reflects the number of shares of our common stock you own. If you own your NiSource shares beneficially through a bank, broker or other nominee, your bank, broker or other nominee will credit your account with the CPG shares you receive in the Distribution. We will not issue physical certificates, even if requested. For a more detailed description, see “The Separation—When and How You Will Receive CPG Shares” beginning on page 64 of this Information Statement.

Q:	If I sell my shares of NiSource common stock on or before the Distribution Date, will I still be entitled to receive shares of CPG common stock in the Distribution?

If you sell your shares of NiSource common stock on or prior to the Distribution Date, you may also be selling your right to receive shares of our common stock. For a more detailed description, see “The Separation—Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement. You are encouraged to consult with your financial advisor regarding the specific implications of selling your NiSource common stock prior to or on the Distribution Date.

Q:	How will fractional shares be treated in the Distribution?

No fractional shares of our common stock will be distributed in connection with the Distribution. Instead, the Distribution Agent will aggregate all fractional shares into whole shares and sell the whole shares in the open market at prevailing market prices. The Distribution Agent will then distribute the aggregate cash

proceeds of the sales, net of brokerage fees and other costs, pro rata to each NiSource stockholder who would otherwise have been entitled to receive a fractional share in the Distribution. For a more detailed description, see “The Separation—Number of Shares You Will Receive” beginning on page 64 this Information Statement.

Q:	What are the U.S. federal income tax consequences of the Distribution to U.S. stockholders?

It is a condition to the completion of the Distribution that NiSource receive an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution for U.S. federal income tax purposes under Section 355 of the Code. The opinion will rely on certain facts and assumptions, and certain representations from us and NiSource regarding the past and future conduct of our respective businesses and other matters. NiSource’s receipt of the opinion is a condition to the Distribution.

Assuming that the Distribution qualifies under Section 355 of the Code, for U.S. federal income tax purposes no income, gain or loss will be recognized by NiSource stockholders subject to U.S. federal income tax, except with respect to cash received in lieu of any fractional shares of our common stock, upon the receipt of shares of our common stock pursuant to the Distribution. However, NiSource stockholders that are subject to U.S. federal income tax generally will recognize gain or loss with respect to any cash received in lieu of any fractional shares.

See “The Separation—Material U.S. Federal Income Tax Consequences of the Separation” beginning on page 67 of this Information Statement and “Risk Factors—Risks Relating to the Separation” on page 49 of this Information Statement for more information regarding the potential tax consequences to you of the Distribution.

Each NiSource stockholder is urged to consult its tax advisor as to the specific tax consequences of the Distribution to such stockholder, including the effect of any state, local or non-U.S. tax laws and of changes in applicable tax laws.

Q:	How will the Distribution affect my tax basis in NiSource common stock?

Assuming that the Distribution is tax-free to NiSource stockholders, your tax basis in NiSource common stock held by you immediately prior to the Distribution will be allocated between such NiSource common stock and our common stock received in the Distribution in proportion to the relative fair market values of each immediately following the Distribution. See “The Separation—Material U.S. Federal Income Tax Consequences of the Separation” beginning on page 67 of this Information Statement for a more detailed description of the effects of the Distribution on your tax basis in NiSource common stock and our common stock.

Q:	What if I want to sell my shares of NiSource common stock or my shares of CPG common stock?

A:	Neither NiSource nor CPG can make any recommendations on the purchase, retention or sale of shares. You should consult with your financial advisors, such as your stockbroker, bank or tax advisor.

If you decide to sell any shares of NiSource common stock after the Record Date, but before the Distribution Date, you should make sure your broker, bank or other nominee understands whether you want to sell your NiSource common stock, our common stock you will be entitled to receive in the Distribution or both. If you sell your NiSource common stock prior to the Record Date or sell your entitlement to receive shares of our common stock in the Distribution on or prior to the Distribution Date, you will not receive any shares of our common stock in the Distribution. For a more detailed description, see “The Separation— Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement.

Q:	Will CPG incur any debt prior to or at the time of the Distribution?

The MLP has a $500 million revolving credit facility, and CPG has entered into a $1,500 million revolving credit facility, which will become effective at the time of the Separation. In addition, on May 22, 2015, CPG sold $2,750.0 million of senior unsecured notes. Prior to the Distribution, we intend to use the net proceeds from that sale to repay $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource and pay a $1,450.0 million special dividend to NiSource. As a result, interest expense incurred on intercompany debt will be eliminated and replaced with interest expense on our credit facilities and our notes. The purpose of the special dividend is to create an appropriate debt-to-capital ratio at each of NiSource and CPG, such that each company is positioned to receive an investment grade credit rating.

Q:	Are there risks associated with owning shares of CPG common stock?

Yes. Our business is subject to both general and specific business risks relating to its operations. Our business is also subject to risks relating to the Separation, and, following the Distribution, we will be subject to risks relating to being an independent, publicly traded company. Accordingly, you should read carefully the information set forth in the section entitled “Risk Factors” beginning on page 31 of this Information Statement.

Q:	Will the number of NiSource shares I own change as a result of the Distribution?

A:	No, the number of shares of NiSource common stock you own will not change as a result of the Distribution.

Q:	What will happen to the listing of NiSource common stock?

A:	After the Distribution, it is anticipated that NiSource will continue to be traded on the New York Stock Exchange (“NYSE”) under the symbol “NI.”

Q:	Does CPG intend to pay cash dividends?

Yes. The declaration and payment of dividends by us in the future will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements, cash flows covenants associated with certain of our debt obligations, which may include maintaining certain debt to capital ratios, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. For a more detailed description, see “The Separation—Dividends” on page 72 of this Information Statement.

Q:	Will CPG common stock trade on a stock market?

Currently, there is no public market for our common stock. Subject to the consummation of the Distribution, we have applied to list our common stock on the NYSE under the symbol “CPGX.” We cannot predict the trading prices for our common stock when such trading begins. We anticipate that trading in shares of our common stock will begin on a when-issued basis on or shortly before the Record Date and will continue up to and including the Distribution Date. The term “when-issued” means that shares can be traded prior to the time shares are actually available or issued. On the first trading day following the Distribution Date, any when-issued trading in respect of our common stock will end and regular way trading in shares of our common stock will begin. “Regular way” trading refers to trading after a security has been issued and typically involves a transaction that settles on the third full business day after the date of trade. If trading begins on a when-issued basis, you may purchase or sell our common stock up to and including the Distribution Date, but your transaction will not settle until after the Distribution Date. For more information regarding regular way trading and when-issued trading, see “The Separation—Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement.

Q:	What will happen to NiSource restricted stock units and performance share awards in connection with the Separation?

A:	We expect that outstanding equity awards at the time of the Separation will be treated as follows:

Restricted Stock Units. We expect the treatment of NiSource restricted stock units (“NiSource RSUs”) that are outstanding on the Distribution Date to depend on the status of the holder. We expect that NiSource RSUs held by any individual who is an employee of CPG immediately following the Separation and unvested NiSource RSUs held by any individual who is a nonemployee director of CPG immediately following the Separation (each, a “CPG Holder”) will convert into CPG restricted stock units (“CPG RSUs”) in a manner that preserves the value of the award following the Separation. We expect that NiSource RSUs held by any individual who is an employee of NiSource immediately following the Separation and unvested NiSource RSUs held by any individual who is a nonemployee director of NiSource immediately following the Separation (each, a “NiSource Holder”) will be adjusted to preserve the value of the award following the Separation. We also expect that vested NiSource RSUs held by any individual who is a non-employee director of either CPG or NiSource immediately following the Separation will be retained and such non-employee director will also receive CPG RSUs equal to the number of shares of CPG stock that such non-employee director would have received if such non-employee director owned the shares subject to the vested NiSource RSUs on the Distribution Date. After the Distribution Date, the NiSource RSUs and CPG RSUs will be subject to substantially the same terms and conditions as the original NiSource RSUs, except that the vesting of awards held by CPG Holders will be based on continued service with CPG.

Performance Share Awards. Similarly, we expect the treatment of NiSource performance share awards (“NiSource PSAs”) that are outstanding on the Distribution Date to be adjusted or converted into CPG awards in a manner that preserves the intended value of such awards following the Separation. The treatment of outstanding NiSource PSAs will depend on the status of the holder as of the Distribution Date and the year in which the award was granted.

NiSource PSAs held by CPG Holders

2013 Awards. We expect that each NiSource PSA granted in 2013 and held by a CPG Holder on the Distribution Date will be replaced with a CPG RSU award, with the number of shares of NiSource common stock earned pursuant to such NiSource PSA to be based on actual performance results through the Distribution Date. The number of such NiSource shares will then be converted into substitute CPG RSUs in a manner that preserves the value of the award following the Separation. Such substitute CPG RSUs will vest on the last day of the performance period to which they relate based on the holder’s service with CPG and will have the same terms and conditions as the corresponding NiSource PSA, except as otherwise described herein.

2014 Awards. We expect that each NiSource PSA granted in 2014 and held by a CPG Holder on the Distribution Date will be replaced with CPG RSUs. With respect to 50% of such NiSource PSA, the number of shares of NiSource common stock that are deemed to have been earned as of the Distribution Date will be equal to 50% of the target number of shares subject to such award. With respect to the remaining 50% of such NiSource PSA, the number of shares of NiSource common stock earned will be based on actual performance results through the Distribution Date. The number of such NiSource shares that are earned or deemed to have been earned will then be converted into substitute CPG RSUs in a manner that preserves the value of the award following the Separation. Such substitute CPG RSUs will vest on the last day of the performance period to which they relate based on the holder’s service with CPG and will have the same terms and conditions as the corresponding NiSource PSA, except as otherwise described herein.

NiSource PSAs held by NiSource Holders

2013 Awards. We expect that each NiSource PSA granted in 2013 and held by a NiSource Holder on the Distribution Date will be adjusted in a manner that preserves the value of the award following the

Separation. The number of shares of NiSource common stock earned pursuant to the NiSource PSA will be based on actual performance results through the Distribution Date. The number of such NiSource shares that are earned will then be adjusted in a manner that preserves the value of the award following the Separation. Each adjusted award will vest on the last day of the performance period to which it relates based on the holder’s continued service with NiSource and will have the same terms and conditions as currently effect, except as otherwise described herein.

2014 Awards. We expect that each NiSource PSA granted in 2014 and held by a NiSource Holder on the Distribution Date will be adjusted in a manner that preserves the value of the award following the Separation. With respect to 50% of such NiSource PSA, the number of shares of NiSource common stock that are deemed to have been earned will be equal to 50% of the target number of shares subject to such NiSource PSA. With respect to the remaining 50% of such NiSource PSA, the number of shares of NiSource common stock earned will be based on actual performance results through the Distribution Date. The number of such shares that are earned or deemed to have been earned will then be adjusted in a manner that preserves the value of the award following the Separation. Each adjusted award will vest on the last day of the performance period to which it relates and will have the same terms and conditions as currently in effect, except as otherwise described herein.

Q:	Will NiSource transfer to CPG any material assets or liabilities prior to the Separation?

Together with the closing of the initial public offering of the MLP, which was completed on February 11, 2015, NiSource contributed its subsidiary CEG to CPG. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of NiSource. Prior to the Separation, NiSource will transfer to CPG assets and liabilities that are immaterial in the aggregate, including all of the outstanding capital stock of Crossroads, a 202-mile interstate natural gas pipeline operating in Indiana and Ohio. In addition, under the Employee Matters Agreement, CPG generally will assume all liabilities and assets relating to employee benefits for current and former CPG employees. In addition, CPG will assume all assets and liabilities related to benefits for current and former CPG employees in NiSource’s defined contribution plans.

Q:	What will be the relationship between NiSource and CPG following the Distribution?

After the Distribution, NiSource will not own any shares of our common stock, and each of CPG and NiSource will be independent, publicly traded companies with their own management and boards of directors. However, in connection with the Separation, we will enter into a number of agreements with NiSource that will govern the Distribution and allocate responsibilities for obligations arising before and after the Separation, including, among others, obligations relating to employees and taxes. NiSource and CPG will enter into Transition Services Agreements, which will provide for the provision of certain transitional services by NiSource to CPG, and vice versa. Additionally, there are operating and maintenance agreements between CPG and NiSource that will not be terminated in connection with the Separation. Columbia Gas of Ohio, an affiliate of NiSource that will no longer be related to us following the Separation, accounted for approximately 13% of our contracted revenues for the year ended December 31, 2014. We expect this commercial activity to continue on similar terms following the Separation, but we cannot provide any assurance that our relationship with Columbia Gas of Ohio will continue on similar terms, or continue at all. For a more detailed description, see “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149 of this Information Statement.

Q:	Will the Distribution of CPG common stock affect the market price of NiSource common stock?

A:	We expect the trading price of shares of NiSource common stock immediately following the Distribution to be lower than immediately prior to the Distribution because its trading price will no longer reflect the value

of our business. Furthermore, until the market has fully analyzed the value of NiSource without our business, the price of shares of NiSource common stock may fluctuate. There can be no assurance that, following the Distribution, the combined value of the common stock of NiSource and the common stock of CPG will equal or exceed what the value of NiSource common stock would have been in the absence of the Distribution.

Q:	Will I have appraisal rights in connection with the Distribution?

A:	No. Holders of NiSource common stock are not entitled to appraisal rights in connection with the Distribution.

Q:	Whom can I contact for more information regarding CPG and the Distribution?

A:	If you have questions relating to the mechanics of the Distribution, you should contact the Distribution Agent at:

NiSource Inc.

c/o Computershare Trust Company, N.A.

P.O. Box 30170

College Station, TX 77842-3170

Phone: (888) 884-7790

Before the Distribution, if you have other questions relating to the Distribution, you should contact NiSource at:

Shareholder Relations

NiSource Inc.

801 East 86^th Avenue

Merrillville, IN 46410

Phone: (877) 647-5990

After the Distribution, if you have any questions relating to CPG, you should contact us at:

Shareholder Relations

Columbia Pipeline Group, Inc.

5151 San Felipe St.

Suite 2500

Houston, TX 77056

Phone: (866) 442-9120

After the Distribution, the transfer agent and registrar for our common stock will be:

Computershare Trust Company, N.A.

P.O. Box 30170

College Station, TX 77842-3170

Phone: (888) 884-7790

Summary of the Separation

The following is a summary of the material terms of the Distribution and other related transactions. Please see “The Separation” beginning on page 61 for a more detailed description of the matters below.

Distributing Company

NiSource Inc., a Delaware corporation. After the Separation, NiSource will not own any shares of our common stock.

Distributed Company

Columbia Pipeline Group, Inc., a Delaware corporation, is a wholly owned subsidiary of NiSource that immediately before the Distribution will hold, through its subsidiaries, all of the assets and liabilities of our business. After the Distribution, CPG will be an independent, publicly traded company.

Distributed Securities

NiSource will distribute all of the shares of our common stock owned by NiSource, which will be 100% of our common stock issued and outstanding immediately prior to the Distribution. Based on the approximately 317,535,860 shares of NiSource common stock outstanding on May 28, 2015 and applying the distribution ratio of one share of our common stock for each share of NiSource common stock, approximately 317,535,860 shares of our common stock will be distributed to NiSource stockholders who hold NiSource common stock as of the Record Date.

Record Date

The Record Date is June 19, 2015.

Distribution Date

The Distribution Date is July 1, 2015.

Distribution Ratio

Each holder of NiSource common stock will receive one share of our common stock for each share of NiSource common stock held on the Record Date. Please note that if you sell your shares of NiSource common stock on or before the Distribution Date, the buyer of those shares may, in certain circumstances, be entitled to receive the shares of our common stock distributed on the Distribution Date. See “The Separation—Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement for more information.

Fractional Shares

The Distribution Agent will not distribute any fractional shares of our common stock to NiSource stockholders. Instead, the Distribution Agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate cash proceeds, net of brokerage fees and other costs, from the sales pro rata to each holder who would otherwise have been entitled to receive a fractional share in the Distribution. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payments made in lieu of fractional shares. The receipt of cash in lieu of fractional shares generally will be taxable to the recipient stockholders as described in “The Separation—Material U.S. Federal Income Tax Consequences of the Separation” beginning on page 67 of this Information Statement.

Distribution Procedures

On the Distribution Date, the Distribution Agent will distribute the shares of our common stock by crediting those shares to book-entry accounts established by the Transfer Agent for persons who were stockholders of NiSource as of the Record Date. Shares of our common stock will be issued only in book-entry form. No paper stock certificates will be issued. You will not be required to make any payment or surrender or exchange your shares of NiSource common

stock or take any other action to receive your shares of our common stock. However, as discussed below, if you sell shares of NiSource common stock in the regular way market between the Record Date and the Distribution Date, you will be selling your right to receive the associated shares of our common stock in the Distribution. Registered stockholders will receive additional information from the Transfer Agent shortly after the Distribution Date. Beneficial stockholders will receive additional information from their brokers, banks or other nominees.

Trading Prior to or on the Distribution Date

It is anticipated that, beginning shortly before the Record Date, and continuing until the Distribution Date, shares of NiSource common stock will trade in two markets on the NYSE, a regular way market and an ex-distribution market. Investors will be able to purchase shares of NiSource common stock without the right to receive shares of our common stock in the ex-distribution market for NiSource common stock. Any holder of NiSource common stock who sells NiSource common stock in the regular way market on or before the Distribution Date will also be selling the right to receive shares of our common stock in the Distribution. You are encouraged to consult with your financial advisor regarding the specific implications of selling shares of NiSource common stock prior to or on the Distribution Date. For a more detailed description, see “The Separation—Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement.

Trading Market and Symbol

Subject to consummation of the Distribution, we intend to list our common stock on the NYSE under the symbol “CPGX.” We cannot predict the trading prices for our common stock when such trading begins. We anticipate that trading in shares of our common stock will begin on a when-issued basis on or shortly before the Record Date and will continue up to and including the Distribution Date. On the first trading day following the Distribution Date, any when-issued trading in respect of our common stock will end and regular way trading in shares of our common stock will begin. If trading begins on a when-issued basis, you may purchase or sell our common stock up to and including the Distribution Date, but your transaction will not settle until after the Distribution Date. For more information regarding regular way trading and when-issued trading, see the section entitled “The Separation—Trading of Common Stock after the Record Date and Prior to the Distribution” beginning on page 70 of this Information Statement.

Relationship with NiSource after the Distribution

Distribution and allocate responsibilities for obligations arising before and after the Separation, including, among others, obligations relating to employees and taxes. In addition, we will enter into Transition Services Agreements pursuant to which NiSource and CPG will provide certain transition services to each other on an interim basis. Additionally, there are operating and maintenance agreements between CPG and NiSource that will not be terminated in connection with the Separation. For a more detailed description, see “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149 of this Information Statement.

Conditions to the Distribution

We expect that the Distribution will be effective on July 1, 2015, provided that the conditions set forth under the caption “The Separation—Conditions to the Distribution” have been satisfied or waived in NiSource’s sole and absolute discretion. However, even if all of the conditions have been satisfied, NiSource may terminate and abandon the Distribution and the related transactions at any time prior to the Distribution Date.

Risk Factors

Our business is subject to both general and specific business risks relating to its operations. Our business is also subject to risks relating to the Separation, and, following the Separation, we will be subject to risks relating to being an independent, publicly traded company. Accordingly, you should read carefully the section entitled “Risk Factors” beginning on page 31 of this Information Statement.

U.S. Federal Income Tax Consequences

The Distribution is conditioned on the receipt by NiSource of an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution satisfactory to the board of directors of NiSource. Assuming the Distribution qualifies under Section 355 of the Code, for U.S. federal income tax purposes no income, gain or loss will be recognized by NiSource stockholders subject to U.S. federal income tax (other than with respect to cash received in lieu of fractional shares), as a result of the Distribution. You should, however, consult your own tax advisor as to the particular tax consequences to you. For a more detailed description, see “The Separation—Material U.S. Federal Income Tax Consequences of the Separation” beginning on page 67 of this Information Statement.

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows the summary historical financial and operating data of CPG and the predecessor of CPG (the “Predecessor”) and pro forma financial data of CPG for the periods and as of the dates indicated. Columbia Pipeline Group, Inc. was formed on September 26, 2014. Together with the closing of the initial public offering of the MLP, which was completed on February 11, 2015, NiSource contributed its subsidiary CEG to CPG. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows of the Predecessor.

CPG is primarily comprised of NiSource’s Columbia Pipeline Group Operations reportable segment, which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource.

The summary historical financial data presented as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 are derived from the audited financial statements of CPG and its Predecessor, which are included elsewhere in this Information Statement. The summary historical financial data presented as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are derived from the unaudited financial statements of CPG and its Predecessor, which are included elsewhere in this Information Statement. The summary historical financial data presented as of December 31, 2012 is derived from the audited financial statements of the Predecessor, which are not included elsewhere in this Information Statement. The summary historical financial data presented as of March 31, 2014 is derived from the unaudited financial statements of the Predecessor, which are not included elsewhere in this Information Statement.

The summary pro forma financial data as of March 31, 2015 and for the fiscal year ended December 31, 2014 and the three months ended March 31, 2015 are derived from our unaudited pro forma consolidated financial statements. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015 give effect to the Separation and related transactions as if they had occurred on January 1, 2014. The unaudited pro forma consolidated balance sheet as of March 31, 2015 gives effect to the Separation and related transactions as if they had occurred on March 31, 2015. The pro forma financial data give pro forma effect to:

MLP Adjustments

•

An adjustment to noncontrolling interest to reflect the public’s interest in the MLP resulting from the MLP’s initial public offering as if it had occurred on January 1, 2014.

Distribution Adjustment

•

The expected issuance of shares of CPG common stock so that shares issued equals the number of shares of NiSource common stock outstanding on the Record Date and the elimination of NiSource’s net investment in CPG.

Financing Adjustments

•

of the notes. Discounts on issuance of the notes will be recorded as a reduction to the face value of the long-term debt and amortized to interest expense using the effective interest method. The following tranches of notes are outstanding:

•

$500.0 million of 2.45% Senior Notes, due 2018

•

$750.0 million of 3.30% Senior Notes, due 2020

•

$1.0 billion of 4.50% Senior Notes, due 2025

•

$500.0 million of 5.80% Senior Notes, due 2045

•

The use of a portion of the proceeds from the senior unsecured note offering for the repayment of $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool between CPG and NiSource.

•

The elimination of interest expense incurred on intercompany debt assumed to have been repaid.

•

The use of a portion of the proceeds from the senior unsecured note offering for a special dividend paid to NiSource in the amount of $1,450.0 million.

•

Total interest expense on our $2,750.0 million of senior unsecured notes and amortization of issuance costs related to our new $2.0 billion senior unsecured revolving credit facilities. The amount is comprised of:

•

interest expense on the notes at an annual weighted average interest rate of 4.04% and a weighted average term of 11 years; and

•

amortization of debt issuance costs, debt discounts and revolving credit facility issuance costs.

No borrowings under the revolving credit facilities are assumed for any period presented. Actual interest expense we incur in future periods may be higher or lower depending on our actual utilization of the revolving credit facilities.

Other Adjustments

•

The adjustment of the provision (benefit) for income taxes for the adjustments made to income (loss) before income taxes at an estimated statutory rate of approximately 38.4% related to the Separation and the portion of taxable income borne by the public’s ownership of the MLP.

•

With the exception of short-term borrowings—affiliated, long-term debt—affiliated and interest expense—affiliated, upon completion of the Separation, amounts reflected in our historical consolidated financial statements as affiliated will be reclassified to unaffiliated.

Following the Separation, we anticipate incurring incremental general and administrative expense as a result of being a stand-alone publicly traded company, including expenses associated with separate corporate services functions, annual and quarterly reporting, tax return preparation, compliance expenses associated with the Sarbanes Oxley Act of 2002 (the “Sarbanes-Oxley Act”), expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, and registrar and transfer agent fees. The unaudited pro forma consolidated financial statements do not reflect these additional stand-alone public company costs. No pro forma adjustment has been made for these expenses as an estimate of these expenses is not objectively determinable.

The following summary historical and unaudited pro forma financial data should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships and Related Party Transactions” and the financial statements and related notes included elsewhere in this Information Statement. Among other things, the historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net. Adjusted EBITDA is not calculated or presented in accordance with generally accepted accounting principles (“GAAP”). We explain this measure under “—Non-GAAP Financial Measures” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.


	Columbia Pipeline Group, Inc. Historical															Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,									Three Months Ended March 31,						Three Months Ended March 31, 2015			Year Ended December 31, 2014
	2014			2013			2012			2015			2014			Three Months Ended March 31, 2015			Year Ended December 31, 2014
				*Predecessor*			*Predecessor*						*Predecessor*
	(in millions, except per share and operating data)
Statement of Operations Data:
Total operating revenues	$	1,348.0		$	1,180.5		$	1,001.3		$	340.0		$	345.8		$	340.0		$	1,348.0
Operating Expenses:
Operation and maintenance		628.4			509.0			375.9			118.4			137.2			146.4			751.6
Operation and maintenance—affiliated		123.2			118.6			106.7			28.0			28.5			—			—
Depreciation and amortization		118.8			107.0			99.4			32.5			29.8			32.5			118.8
Gain on sale of assets		(34.5	)		(18.6	)		(0.6	)		(5.3	)		(17.5	)		(5.3	)		(34.5	)
Property and other taxes		67.1			62.2			59.2			19.1			18.5			19.1			67.1

Total operating expenses	$	903.0		$	778.2		$	640.6		$	192.7		$	196.5		$	192.7		$	903.0

Equity Earnings in Unconsolidated Affiliates		46.6			35.9			32.2			15.4			9.8			15.4			46.6

Operating Income	$	491.6		$	438.2		$	392.9		$	162.7		$	159.1		$	162.7		$	491.6

Other Income (Deductions)
Interest expense		—			—			—			—			—			(28.0	)		(113.2	)
Interest expense—affiliated		(62.0	)		(37.9	)		(29.5	)		(18.3	)		(12.1	)		—			—
Other, net		8.8			17.9			2.1			4.6			1.9			4.6			8.8

Total Other Deductions		(53.2	)		(20.0	)		(27.4	)		(13.7	)		(10.2	)		(23.4	)		(104.4	)

Income from continuing operations before income taxes		438.4			418.2			365.5			149.0			148.9			139.3			387.2
Income taxes		169.7			146.5			139.3			51.9			55.9			48.1			132.6

Income from continuing operations		268.7			271.7			226.2			97.1			93.0			91.2			254.6
Income (Loss) from Discontinued Operations—net of taxes		(0.6	)		9.0			(2.2	)		—			(0.2	)		—			(0.6	)

Net income	$	268.1		$	280.7		$	224.0		$	97.1		$	92.8		$	91.2		$	254.0

Less: Net income attributable to noncontrolling interest											7.1						14.1			42.0


	Columbia Pipeline Group, Inc. Historical															Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,									Three Months Ended March 31,						Three Months Ended March 31, 2015		Year Ended December 31, 2014
	2014			2013			2012			2015			2014			Three Months Ended March 31, 2015		Year Ended December 31, 2014
				*Predecessor*			*Predecessor*						*Predecessor*
	(in millions, except per share and operating data)
				*Predecessor*			*Predecessor*						*Predecessor*
Net Income attributable to Columbia Pipeline Group, Inc.										$	90.0			—		$	77.1	$	212.0

Basic Pro Forma Earnings per Share⁽¹⁾
Continuing operations											—			—		$	0.24	$	0.67
Discontinued operations											—			—		$	—	$	—
Diluted Pro Forma Earnings per Share⁽¹⁾
Continuing operations											—			—		$	0.24	$	0.67
Discontinued operations											—			—		$	—	$	—
Balance Sheet Data (at period end):
Total assets	$	8,157.5		$	7,281.2		$	6,640.2		$	8,970.0		$	7,435.6		$	8,397.3
Net property, plant and equipment		4,958.6			4,302.1			3,740.4			5,114.9			4,402.6			5,114.9
Long-term debt, excluding amounts due within one year		—			—			—			—			—			2,746.0
Long-term debt-affiliated, excluding amounts due within one year		1,472.8			819.8			754.7			1,848.2			991.4			—
Total liabilities		3,981.2			3,365.6			2,896.9			4,021.0			3,427.0			4,898.3
Total parent’s net equity		4,176.3			3,915.6			3,743.3			4,949.0			4,008.6			3,499.0
Statement of Cash Flow Data:
Net cash from (used for):
Operating activities	$	564.8		$	457.2		$	471.4		$	163.8		$	203.6
Investing activities		( 860.1	)		(790.9	)		(452.8	)		(852.8	)		(163.8	)
Financing activities		295.4			333.1			(17.7	)		695.8			(39.9	)
Other Data:
Adjusted EBITDA	$	601.0		$	550.4		$	492.8		$	198.1		$	186.5		$	198.1	$	601.0
Less: Adjusted EBITDA attributable to non-controlling interest										$	9.7					$	16.6	$	50.3
Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.										$	188.4					$	181.5	$	550.7
Maintenance capital expenditures		143.4			132.7			209.6			21.5			21.3
Expansion capital expenditures		700.5			664.8			280.0			169.5			137.9
Operating Data:⁽²⁾
Contracted firm capacity (MMDth/d)		13.2			12.8			13.1			15.3			14.2
Throughput (MMDth)		2,006.1			1,997.3			2,200.0			643.0			650.8
Natural gas storage capacity (MMDth)		287			287			283			287			287

(1)

Historical earnings per share are not presented because we did not have common stock that was part of our capital structure for the periods presented. The calculation of pro forma earnings per share is calculated by dividing the pro forma net income by the weighted average number of shares of NiSource common stock outstanding for the periods indicated. The calculation of pro forma diluted net income per share is calculated by dividing the pro forma net income by the weighted average number of shares of NiSource common stock outstanding and diluted shares of common stock outstanding for the periods indicated. This calculation may not be indicative of the dilutive effect that will actually result from share-based awards subsequently transferred to or granted by CPG.

(2)	Excludes equity investments.

Non-GAAP Financial Measures

Adjusted EBITDA

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP Net Income or Net Cash Flows from Operating Activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect Net Income and Net Cash Flows from Operating Activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following tables present a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.


	Columbia Pipeline Group, Inc. Historical										Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,						Three Months Ended March 31,				Three Months Ended March 31, 2015		Year Ended December 31, 2014
	2014		2013		2012		2015		2014		Three Months Ended March 31, 2015		Year Ended December 31, 2014
			*Predecessor*		*Predecessor*				*Predecessor*
	(in millions)
Net Income	$	268.1	$	280.7	$	224.0	$	97.1	$	92.8	$	91.2	$	254.0
Add:
Interest Expense		—		—		—		—		—		28.0		113.2
Interest expense—affiliated		62.0		37.9		29.5		18.3		12.1		—		—
Income taxes		169.7		146.5		139.3		51.9		55.9		48.1		132.6
Depreciation and amortization		118.8		107.0		99.4		32.5		29.8		32.5		118.8
Distributions of earnings received from equity investees		37.8		32.1		34.9		18.3		7.6		18.3		37.8
Less:
Other, net		8.8		17.9		2.1		4.6		1.9		4.6		8.8
Equity earnings in unconsolidated affiliates		46.6		35.9		32.2		15.4		9.8		15.4		46.6

Adjusted EBITDA	$	601.0	$	550.4	$	492.8	$	198.1	$	186.5	$	198.1	$	601.0

Less:
Adjusted EBITDA attributable to non-controlling interest								9.7				16.6		50.3

Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.								$188.4				$181.5	$	550.7


	Columbia Pipeline Group, Inc. Historical
	Year Ended December 31,									Three Months Ended March 31,
	2014			2013			2012			2015			2014
				*Predecessor*			*Predecessor*						*Predecessor*
	(in millions)
Net Cash Flows from Operating Activities	$	564.8		$	457.2		$	471.4		$	163.8		$	203.6
Interest expense—affiliated		62.0			37.9			29.5			18.3			12.1
Current taxes		27.1			(27.4	)		90.3			15.8			26.9
Other adjustments to operating cash flows		28.2			22.1			(1.4	)		(3.2	)		15.4
Changes in assets and liabilities		(81.1	)		60.6			(97.0	)		3.4			(71.5	)

Adjusted EBITDA	$	601.0		$	550.4		$	492.8		$	198.1		$	186.5

Less:
Adjusted EBITDA attributable to non-controlling interest											9.7

Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.										$	188.4

RISK FACTORS

Our business, the Separation and our common stock are subject to a number of risks and uncertainties. You should carefully consider the risks and uncertainties described below, together with all of the other information in this Information Statement. Based on the information currently known to us, we believe that the following information identifies the most significant risk factors affecting our business, the Separation and our common stock. However, the risks and uncertainties we face are not limited to those described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially adversely affect our results of operations, cash flows and financial condition. This Information Statement also contains forward-looking statements that involve risks and uncertainties. You should carefully read the section entitled “Cautionary Note Concerning Forward-Looking Statements” on page 59 of this Information Statement.

If any of the following risks were to occur, our business, financial condition, results of operations, cash flows and cash available for the payment of dividends could be materially adversely affected. In that case, we might not be able to pay dividends to our stockholders, the trading price of our common stock could materially decline and you could lose all or part of your investment.

Risks Relating to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses to enable us to pay dividends to our stockholders.

The amount of cash we generate from our operations will fluctuate based on, among other things:

•

the rates we charge for our transmission, storage and gathering services;

•

the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;

•

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;

•

legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility;

•

the imposition of requirements by state agencies that materially reduce the demand of our customers, such as LDCs and power generators, for our pipeline services;

•

the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;

•

the creditworthiness of our customers;

•

the level of our operating and maintenance and general and administrative costs;

•

the level of capital expenditures we incur to maintain our assets;

•

regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region;

•

successful development of LNG export terminals in the eastern or northeastern United States, which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system;

•

changes in insurance markets and the level, types and costs of coverage available, and the financial ability of our insurers to meet their obligations;

•

changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;

•

changes in accounting rules and/or tax laws or their interpretations;

•

nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and

•

changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

In addition, the actual amount of cash we will have available for the payment of dividends will depend on other factors, including:

•

the level and timing of capital expenditures we make;

•

construction costs;

•

fluctuations in our working capital needs;

•

our ability to borrow funds and access capital markets;

•

our debt service requirements and other liabilities;

•

restrictions contained in our existing or future debt agreements, including our credit facilities; and

•

the cash distribution policy of the MLP.

Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations on a per share of common stock basis.

Even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations on a per share of common stock basis. Any expansion project involves potential risks, including, among other things:

•

service interruptions or increased downtime associated with our projects, including the reversal of Columbia Gulf’s pipelines;

•

a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the project or acquisition;

•

an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits, among other factors;

•

the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;

•

the diversion of our management’s attention from other business concerns;

•

mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, including synergies and potential growth;

•

an inability to successfully integrate the businesses we build;

•

an inability to receive cash flows from a newly built asset until it is operational; and

•

unforeseen difficulties operating in new product areas or new geographic areas.

If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per share of common stock, our ability to pay dividends to our stockholders may be reduced.

The amount of cash we have available for the payment of dividends to our stockholders depends primarily on our cash flow and not solely on profitability, which may prevent us from paying dividends even during periods when we record net income.

The amount of cash we have available for the payment of dividends depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which

will be affected by non-cash items. As a result, we may pay cash dividends during periods when we record net losses for financial accounting purposes and may be unable to pay cash dividends during periods even when we record net income.

The MLP may not have sufficient cash from operations to pay the minimum quarterly distribution to us on our subordinated units following the establishment of cash reserves and payment of costs and expenses and payment of the minimum quarterly distribution on its common units.

The MLP may not have sufficient cash from operations each quarter to pay the minimum quarterly distribution of $0.1675 per unit, or $0.67 per unit per year. The amount of cash the MLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate based on, among other things:

•

the rates the MLP charges for its transmission, storage and gathering services;

•

the level of firm transmission and storage capacity sold and volumes of natural gas the MLP transports, stores and gathers for its customers;

•

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in the MLP’s end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact the MLP’s ability to renew and replace firm transmission and storage agreements;

•

legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates the MLP can charge, how the MLP contracts for services, the MLP’s existing contracts, operating costs and operating flexibility;

•

the imposition of requirements by state agencies that materially reduce the demand of Columbia OpCo’s customers, such as LDCs and power generators, for its pipeline services;

•

the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;

•

the creditworthiness of the MLP’s customers;

•

the level of Columbia OpCo’s operating and maintenance and general and administrative costs;

•

the level of capital expenditures Columbia OpCo incurs to maintain its assets;

•

regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region;

•

successful development of LNG export terminals in the eastern or northeastern United States, which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system;

•

changes in insurance markets and the level, types and costs of coverage available, and the financial ability of the MLP’s insurers to meet their obligations;

•

changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;

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changes in accounting rules and/or tax laws or their interpretations;

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nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and

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changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

In addition, the actual amount of cash the MLP will have available for distribution will depend on other factors, including:

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the level and timing of capital expenditures the MLP or Columbia OpCo makes;

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construction costs;

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fluctuations in the MLP’s or Columbia OpCo’s working capital needs;

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the MLP’s or Columbia OpCo’s ability to borrow funds and access capital markets;

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the MLP’s or Columbia OpCo’s debt service requirements and other liabilities;

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restrictions contained in the MLP’s or Columbia OpCo’s existing or future debt agreements; and

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the amount of cash reserves established by the MLP’s general partner.

As a result of these factors, the amount of cash the MLP distributes in any quarter to us may fluctuate significantly from quarter to quarter and may be significantly less than the minimum quarterly distribution amount that we expect to receive.

We and our affiliates, including the general partner of the MLP, may have conflicts of interest with the MLP.

Conflicts may arise in the future between the interests of CPG and our affiliates, including the general partner of the MLP, and the MLP. The partnership agreement of the MLP permits the board of directors of the general partner of the MLP to form a conflicts committee of independent directors and to submit to that committee matters that the board believes may involve conflicts of interest. There can be no assurance that the conflicts committee will resolve any conflict of interest in our favor.

We rely on certain key customers for a significant portion of our revenues. Columbia Gas of Ohio, an affiliate of NiSource, and Washington Gas Light Company accounted for approximately 13%, and 9% of our contracted revenues, respectively, for the year ended December 31, 2014. The loss of all or even a portion of the contracted volumes of these or other customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to pay dividends to our stockholders, unless we are able to contract for comparable volumes from other customers at favorable rates.

The expansion of our existing assets and construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition, and reduce our cash from operations on a per share of common stock basis.

One of the ways we intend to grow our business is through the expansion of our existing assets and construction of new energy infrastructure assets. The construction of additions or modifications to our existing pipelines, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant capital that we may be unable to raise. If we undertake these projects they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues from such project until the project is completed. We may also construct facilities to capture anticipated future growth in production or demand in regions such as the Marcellus and Utica shale production areas, which may not materialize or where contracts are later cancelled.

Since we are not engaged in the exploration for and development of natural gas reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of

operations and financial condition. The construction of new pipelines may also require us to obtain new rights-of-way, and it may become more expensive for us to obtain these new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus shale area. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

A substantial portion of our organic growth projects is supported by binding precedent agreements that are subject to certain conditions, which, if not satisfied, would permit the customer to opt out of the agreement.

A substantial portion of our $5.0 billion in estimated capital costs for organic growth projects are supported by a combination of (i) service agreements, which are long-term legally binding obligations that secure our revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either us or the customer to terminate the agreement. These conditions include, among others, the receipt of governmental approvals and the achievement of certain in-service dates. If the conditions in a precedent agreement are not satisfied and the customer elects to terminate the agreement, the underlying project and the related revenue streams could be at risk, which could have a material adverse effect on our financial condition, results of operations and our ability to pay dividends to our stockholders.

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for the payment of dividends to our stockholders.

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in response to historically low natural gas prices, a number of large natural gas producers have announced their intention to re-evaluate and/or reduce their drilling programs in certain areas. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase the payment of dividends to our stockholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.

The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves.

We receive cash from royalty payments on our mineral rights positions through our working interests and overriding royalty interests. We are not the operator of the wells from which we receive royalty payments, and therefore, we are not able to control the timing of exploration or development efforts, or associated costs.

Through our subsidiary, CEVCO, we own production rights to approximately 460,000 acres in the Marcellus and Utica shale areas and have subleased the production rights in four storage fields and have also contributed our production rights in one other field. We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:

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the timing and amount of capital expenditures;

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the timing of initiating the drilling and recompleting of wells;

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the extent of operating costs;

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selection of technology and drilling and completion methods; and

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the rate of production of reserves, if any.

If the royalty payments we receive from our sublessees are reduced, our ability to pay dividends to our stockholders could be adversely affected.

Our revenues from CEVCO royalty interests will decrease if production on our subleased production rights declines, which would reduce the amount of cash we have available for the payment of dividends to our stockholders.

The amount of the royalty payments we receive on our subleased production rights depends in part on the amount of production on our properties. In addition, the royalty payments vary with the natural gas liquids and oil content of the production. For example, “dry gas” wells produce mainly natural gas, or methane, as opposed to “wet gas” wells, which produce methane along with other byproducts such as ethane, which may result in additional revenue streams from such production. During 2013 and 2012, natural gas prices remained relatively low, leading some producers to announce significant reductions to their drilling plans in dry gas areas. A significant reduction in the level of production on our properties could adversely affect on our ability to pay dividends to our stockholders. Similarly, increased dry gas production attributable to our royalty interest would generally result in less revenue for us than the production of wet gas (i.e., production that includes oil and natural gas liquids). As a result, any significant decline in production volumes or decrease in wet gas production would reduce our royalty payments, which could adversely affect our ability to pay dividends to our stockholders.

Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade pipelines and other facilities. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; and incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates polychlorinated biphenyls (“PCBs”) at specific gas transmission facilities pursuant to a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs ceased on January 31, 2015. As of December 31, 2014, Columbia Gas Transmission had recorded $1.8 million to cover costs associated with PCB remediation related to this AOC.

Moreover, new, modified or stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our or our customer’s compliance costs, pollution mitigation costs, or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. Our compliance with such new or amended legal requirements could result in our incurring significant additional expense and operating restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers, to whom we provide our services, may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business. For example, a number of state and regional legal initiatives have emerged in recent years that seek to reduce greenhouse gas (“GHG”) emissions and the U.S. Environmental Protection Agency (“EPA”), based on its findings that emissions of greenhouse gases present a danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore processing sources in the United States on an annual basis. Such regulations or any new federal laws restricting emissions of GHGs from customer operations could delay or curtail their activities and, in turn, adversely affect our business. In another example, the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing while the U.S. Congress, certain state agencies, and some local governments have from time to time considered or adopted and implemented legal requirements that have imposed, and in the future could continue to impose, new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, which requirements could cause our customers to incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our transportation services.

In another example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas sector facilities, including natural gas transmission infrastructure and equipment, as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. If proposed and adopted, new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which costs, delays or curtailment could adversely affect our business.

Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial or compliance obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders. Please read “Business—Environmental and Occupational Health and Safety Regulation” for more information.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair, or preventative or remedial measures.

The United States Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In addition, the DOT is examining the possibility of expanding integrity management principles beyond high consequence areas.

We have incurred costs of approximately $212 million ($107.2 million in capital costs and $104.8 million in expenses) between 2009 and 2014 associated with the assessment of our pipelines to implement the integrity management program. We currently anticipate we will continue to incur similarly substantial capital and operating maintenance costs in the future.

There may be additional costs associated with any other major repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. In addition, any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business—Pipeline Safety and Maintenance” for more information.

We may incur significant costs from time to time in order to comply with DOT regulations regarding the design, strength and testing of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.

DOT regulations govern the design strength and testing of our pipelines. The required design strength and testing of the pipe depends upon the population density near the pipeline. In the event the population density around any specific section of our pipelines increases above levels established by the DOT, we may be required to upgrade the section of our pipelines traversing through the area with pipe of higher strength or, in some cases, retest the pipe, unless a waiver from the DOT is obtained. While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur significant expenses in the future in response to increases in population density near sections of our pipelines.

We may incur significant costs and liabilities to comply with new DOT regulations that are anticipated to be issued in the future.

The Natural Gas Pipeline Safety Act (“NGPSA”) was amended on January 3, 2012 when the President signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The DOT issued an advanced notice of proposed rulemaking in August of 2011 that addressed approximately 15 specific topics associated with the legislation. The topics included the role of valves in mitigating consequences, metal loss evaluation and response, pressure testing to address manufacturing and construction threats, expanding integrity management principles, underground storage of natural gas and leak detection systems, among other topics. In addition, the DOT is working on other rulemaking topics such as operator verification of records confirming the maximum allowable operating pressure of certain pipelines and integrity verification of previously untested pipelines or pipelines with other potential integrity issues, as well as others. There may be additional costs and liabilities associated with many of these pending future requirements. We continue to monitor regulatory developments associated with these pending regulations to help anticipate potential future operational and financial risks associated with the implementation of any new regulations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and Hazardous Liquid Pipeline Safety Act pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of Pipeline Hazardous Materials Safety Administration (“PHMSA”) rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.

In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders.

Our natural gas transportation and storage operations are subject to extensive regulation by the FERC.

Our business operations are subject to extensive regulation by the FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. Compliance with these requirements can be costly and burdensome and FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC’s regulations. We cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation and storage business or the effect such regulation could have on our business, financial condition and results of operations.

Rate regulation could limit our ability to recover the full cost of operating our pipelines, including a reasonable return, and our ability to pay dividends to our stockholders.

The rates we can charge for our natural gas transportation and storage operations are regulated by the FERC pursuant to the Natural Gas Act of 1938 (the “Natural Gas Act”). Under the Natural Gas Act, we may only charge rates that have been determined to be just and reasonable by the FERC and are prohibited from unduly preferring or unreasonably discriminating against any person with respect to our rates or terms and conditions of service. The FERC establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the volumes of gas being transported or stored, the rate design, the allocation of costs between services, the capital structure and the rate of return a natural gas company is permitted to earn.

We may not be able to recover all of our costs through existing or future rates. Proposed rate increases may be challenged by protest and allowed to go into effect subject to refund. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected.

Our existing rates may be challenged by complaint or sua sponte by the FERC. In recent years, the FERC has exercised this authority with respect to several other pipeline companies. In a potential proceeding involving the challenge of our existing rates, the FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. Any successful challenge against our rates could have an adverse impact on our revenues associated with providing transportation and storage services. In addition, future changes to laws, regulations and policies may impair our ability to recover costs and the ability to pay dividends to our stockholders.

Certain of our gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as result of these “negotiated rate” contracts could decrease our cash flow.

We are exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements. The FERC-approved tariffs of our transmission and storage companies provide for annual filings to adjust the amount of gas retained from customers to eliminate any overages or shortfalls from the prior year. Our gathering companies have contracts that provide for specified levels of fuel retainage, so they may find it necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our gathering systems could have a material adverse effect on our business, financial condition, results of operations and ability to pay dividends to our stockholders.

We could be subject to penalties and fines if we fail to comply with FERC regulations.

Should the FERC find that we have failed to comply with all applicable FERC-administered statutes, rules, regulations and orders, or the terms of our tariffs on file with the FERC, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005 (“EPAct 2005”), the FERC has civil penalty authority under the Natural Gas Act and Natural Gas Policy Act of 1978 (“NGPA”) to impose penalties for violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

Certain of our assets may become subject to FERC regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the Natural Gas Act has been the subject of substantial litigation, and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If more of our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

We do not own all of the land on which our pipelines are located, which could disrupt our operations.

We do not own all of the land on which our pipelines are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights required to conduct our operations. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. In certain instances, our rights-of-way may be subordinate to that of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to pay dividends to our stockholders.

Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:

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aging infrastructure, mechanical or other performance problems;

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damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

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inadvertent damage from third parties, including from construction, farm and utility equipment;

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leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

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operator error;

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environmental hazards, such as natural gas leaks, product and waste spills, pipeline and tank ruptures, and unauthorized discharges of products, wastes and other pollutants into the surface and subsurface environment, resulting in environmental pollution; and

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explosions and blowouts.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations or services. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

Debt that we incur in the future may limit our flexibility to obtain additional financing and to pursue other business opportunities.

At the time of the Distribution, we expect to have $2,750.0 million of senior unsecured notes outstanding in addition to CPG’s $1,500 million revolving credit facility, of which a minimum of $750 million will be dedicated as credit support for Columbia OpCo and its subsidiaries in connection with a money pool arrangement. In addition, the MLP has a $500 million revolving credit facility. Our existing and future level of debt, including the MLP’s future level of debt, could have important consequences to us, including the following:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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the funds that we have available for operations and payment of dividends to stockholders will be reduced by that portion of our cash flow required to make principal and interest payments on outstanding debt; and

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our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Restrictions under our new or any future credit facilities could adversely affect our business, financial condition, results of operations and ability to pay dividends to our stockholders.

The MLP has a $500 million credit facility, and CPG has entered into a credit facility that will become effective as of the Distribution Date. Our new credit facilities limit and any future credit facility we may enter into is likely to limit, our ability to, among other things:

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pay dividends if any default or event of default occurs;

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incur additional indebtedness or guarantee other indebtedness;

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grant liens or make certain negative pledges;

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make certain loans or investments;

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engage in transactions with affiliates;

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transfer, sell or otherwise dispose of all or substantially all of our or the MLP’s assets; or

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enter into a merger, consolidate, liquidate, wind up or dissolve.

Furthermore, any new or future credit facility may also contain covenants requiring us to maintain certain financial ratios and tests. Our ability to comply with the covenants and restrictions contained in our credit facilities may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If CPG or the MLP violates any of the restrictions, covenants, ratios or tests in the applicable credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and

demand repayment of amounts outstanding, and our lenders’ commitment to make further loans to us may terminate and we and/or the MLP will be prohibited from making any distributions to equity holders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our credit facilities or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to pay dividends to our stockholders.

Deterioration in our credit profile could increase our costs of borrowing money, adversely affect our business relationships and limit our access to the capital markets and commercial credit.

Upon the Separation we expect to initially receive an investment grade credit rating from Standard & Poor’s Rating Service and Moody’s Investor Service. (Ratings from credit agencies are not recommendations to buy, sell or hold our securities, and each rating should be evaluated independently of any other rating.) Once received, our credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our borrowing costs would increase and our funding sources could decrease. In addition, a failure by us to maintain an investment grade credit rating could affect our business relationships with suppliers and operating partners. We have certain agreements that contain “ratings triggers” that require increased collateral if our credit is rated below BBB- by Standard & Poor’s or Baa3 by Moody’s. These agreements are primarily for insurance purposes and for the physical purchase or sale of power. The collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $15 million. In addition to agreements with ratings triggers, there are other agreements that contain “adequate assurance” or “material adverse change” provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business. A credit downgrade could also adversely affect the availability and cost of capital needed to fund the growth investments that are a central element of our long-term business strategy.

There can be no assurance that we will be able to access the capital markets to raise debt or equity financing on acceptable terms.

From time to time, we will need to access the capital markets to obtain equity or long-term or short-term debt financing. Although we believe that the sources of capital in place at the time of the Distribution will permit us to finance our near-term operations on acceptable terms and conditions, our access to, and the availability of, financing on acceptable terms and conditions in the future will be impacted by many factors, including, without limitation: (1) our financial performance, (2) our credit ratings or absence of a credit rating, (3) the liquidity of the overall capital markets, (4) the terms of our outstanding debt, and (5) the state of the economy. There can be no assurance that we will have access to the capital markets on terms acceptable to us or at all.

Substantially all of our cash will be generated from cash distributions from Columbia OpCo. Our new credit facilities have customary covenants and restrictions on us and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facilities. CPG is an additional guarantor of the MLP’s credit facility. In addition, on May 22, 2015, CPG sold $2,750.0 million of senior unsecured notes. Prior to the Distribution, we intend to use the net proceeds from that sale to repay $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource and pay a $1,450.0 million special dividend to

NiSource. Columbia OpCo, CEG, and OpCo GP will guarantee such indebtedness. There is no agreement between us and Columbia OpCo limiting the amount of our indebtedness that Columbia OpCo will be obligated to guarantee. The amount of CPG’s total indebtedness and the MLP’s indebtedness in general, as well as the amount that is guaranteed by Columbia OpCo and CPG, respectively, may limit the ability of Columbia OpCo or CPG to borrow to fund its operations, capital expenditures or growth strategy. Furthermore, to the extent that Columbia OpCo or CPG is required to guarantee such indebtedness, Columbia OpCo and CPG could be subject to significant operating and financial restrictions. For example, these restrictions could include covenants limiting Columbia OpCo’s and CPG’s ability to:

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make investments and other restricted payments;

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incur additional indebtedness or issue preferred stock;

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create liens;

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sell all or substantially all of its assets or consolidate or merge with or into other companies; and

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engage in transactions with affiliates.

These covenants or any more restrictive covenants agreed to by us in the future could adversely affect Columbia OpCo’s and CPG’s ability to finance future business opportunities and make cash distributions. A breach by Columbia OpCo or CPG of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing that debt, including Columbia OpCo, CPG and their assets. In addition, any acceleration of debt under CPG’s bank syndicated credit facility could constitute a default under our other debt, which Columbia OpCo and/or CPG may also guarantee. If our lenders or other debt creditors were to proceed against Columbia OpCo’s or CPG’s assets, the value of Columbia OpCo and CPG could be significantly reduced which could adversely affect the value of our common stock.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available for the payment of dividends could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines. For example, our pipelines interconnect with virtually every major interstate pipeline in the eastern portion of the United States and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections were to become unavailable for current or future volumes of natural gas due to repairs, damage, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect which causes a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders.

The current Columbia Gulf and Columbia Gas Transmission pipeline infrastructure is aging, which may adversely affect our business, results of operations, financial condition and ability to pay dividends to our stockholders.

The Columbia Gulf and Columbia Gas Transmission pipeline systems have been in operation for many years, with some portions of these pipelines being more than 50 years old. Segments of the Columbia Gulf and Columbia Gas Transmission pipeline systems are located in or near areas determined to be high consequence areas. We implement integrity management testing of the pipelines that we operate, including the Columbia Gulf and Columbia Gas Transmission pipelines, and we repair, remediate or replace segments on those pipelines as necessary when anomaly conditions are identified during the integrity testing process or are determined to have

occurred during the course of operations. Nonetheless, we also are currently investing significant capital over the next several years to replace aging infrastructure, including replacement of the relatively older pipe found on the Columbia Gulf and Columbia Gas Transmission systems. If, due to their age, these pipeline sections were to become unexpectedly unavailable for current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could result in a material adverse impact on our business, financial condition and results of operation as well as our ability to pay dividends to our stockholders.

LNG export terminals may not be developed in the Gulf Coast region or may be developed outside our areas of operations.

We are in the process of reversing the flow of the Columbia Gulf pipeline system in order to supply new and developing LNG export facilities located along the Gulf Coast. However, we may not realize expected increases in future natural gas demand from LNG exports due to factors including:

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new projects may fail to be developed;

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new projects may not be developed at their announced capacity;

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development of new projects may be significantly delayed;

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new projects may be built in locations that are not connected to our system; or

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new projects may not influence sources of supply on our system.

Similarly, the development of new, or the expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas on our assets. This could reduce the amount of natural gas transported by our pipeline.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them and inability to re-market the resulting capacity could have a material adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders. We may not be able to effectively re-market such capacity during and after insolvency proceedings involving a customer.

Our strategy to grow our business is dependent in part on the MLP’s ability to access capital markets that result in an increase in our cash available.

We intend to utilize the significant experience of our management team to execute our growth strategy, including the construction, development and integration of additional energy infrastructure assets. Our ability to acquire these additional assets is dependent in part on the MLP’s ability to access capital markets resulting in an increase in our cash available for investment. If the MLP is unable to access capital markets on acceptable terms, the MLP’s ability to acquire additional interests in Columbia OpCo from CEG and our future growth and ability to increase dividends may be adversely affected.

We may be unable to make acquisitions from third parties as an alternative avenue to growth. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our earnings. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

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mistaken assumptions about revenues and costs, including synergies;

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the inability to successfully integrate the businesses we acquire;

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the inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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mistaken assumptions about the overall costs of equity or debt;

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the diversion of management’s attention from other business concerns;

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unforeseen difficulties in connection with operating in new product areas or new geographic areas; and

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customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and stockholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States, whether or not targeted at our assets or the assets of our customers, could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from customers or disruptions of fuel supplies and markets if domestic and global utilities are direct targets or indirect casualties of an act of terror or war. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

A failure in our computer systems or a cyber-attack on any of our facilities or any third parties’ facilities upon which we rely may adversely affect our ability to operate.

We rely on technology to run our businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of our business, including the generation, transmission and distribution of electricity, operation of our gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our businesses and could result in a financial loss and possibly do harm to our reputation.

Additionally, our information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach our cyber-defenses. Although we attempt to maintain adequate defenses to these attacks and work through industry groups and trade associations to identify common threats and assess our countermeasures, a security breach of our information systems could (i) impact the reliability of our transmission and storage systems and potentially negatively impact our compliance with certain mandatory reliability standards, (ii) subject us to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to our customers or employees or (iii) impact our to manage our businesses.

Sustained extreme weather conditions and climate change may negatively impact our operations.

We conduct our operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather-related stress on our infrastructure may reveal weaknesses in our systems not

previously known to us or otherwise present various operational challenges across all business segments. Although we make every effort to plan for weather-related contingencies, adverse weather may affect our ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. We endeavor to minimize such service disruptions, but may not be able to avoid them altogether.

There is also a concern that climate change may exacerbate the risks to physical infrastructure arising from significant physical effects, such as increased severity and frequency of storms, droughts and floods as well as associated with heat and other extreme weather conditions. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the costs we incur in providing our products and services, impacting the demand for and consumption of our products and services (due to changes in both costs and weather patterns), and affecting the economic health of the regions in which we operate.

Growing competition in the gas transportation and storage industries could result in the failure by customers to renew existing contracts.

As a consequence of the increase in competition and the shift in natural gas production areas, customers such as LDCs and other end users may be reluctant to enter into long-term service contracts. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. Our inability to renew or replace our current contracts as they expire and respond appropriately to changing market conditions could materially impact our financial results and cash flows.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse impact on our operations.

Our business is dependent on our ability to attract, retain and motivate employees. Competition for skilled employees in some areas is high and we may experience difficulty in recruiting and retaining employees, particularly given the Separation. The inability to recruit and retain these employees could adversely affect our business and future operating results. We seek to mitigate some of this risk by training our management on how to attract and select the needed talent and also measure our level of employee engagement annually, developing action plans where necessary to improve our workplace, but there is no assurance that such mitigation measures will be effective.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Our assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. All of the insurance policies relating to our assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies ranges from 30 to 45 days. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and we may elect to self-insure portions of our asset portfolio. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums to cover our assets and operations. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The

unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations, and therefore on our ability to pay dividends to our stockholders.

Adverse economic and market conditions or increases in interest rates could reduce net revenue growth, increase costs, decrease future net income and cash flows and impact capital resources and liquidity needs.

While the national economy is experiencing some recovery from the recent downturn, we cannot predict how robust the recovery will be or whether or not it will be sustained.

Continued sluggishness in the economy impacting our operating jurisdictions could adversely impact our ability to grow our customer base and collect revenues from customers, which could reduce net revenue growth and increase operating costs. An increase in the interest rates we pay would adversely affect future net income and cash flows. In addition, we depend on debt to finance our operations, including both working capital and capital expenditures, and would be adversely affected by increases in interest rates. At the time of the Distribution, we expect to have $2.75 billion in outstanding indebtedness, none of which will be subject to variable interest rates.

If the current economic recovery remains slow or credit markets again tighten, our ability to raise additional capital or refinance debt at a reasonable cost could be negatively impacted. Refer to Note 3, “Transactions with Affiliates—Long-term Debt,” in the Company’s audited Notes to Consolidated and Combined Financial Statements for information related to outstanding long-term debt and maturities of that debt.

Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.

The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and may yield uncertain returns, which fall below our projected rates of return. A decline in the market value of assets may increase the funding requirements of the obligations under the defined benefit pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, which could potentially increase funding requirements. Further, the funding requirements of the obligations related to these benefits plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. Ultimately, significant funding requirements and increased pension expense could negatively impact our results of operations and financial condition.

We have significant goodwill and definite-lived intangible assets. An impairment of goodwill or definite-lived intangible assets could result in a significant charge to earnings.

In accordance with GAAP, we test goodwill for impairment at least annually and review our definite-lived intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill also is tested for impairment when factors, examples of which include reduced cash flow estimates, a sustained decline in stock price or market capitalization below book value, indicate that the carrying value may not be recoverable. We would be required to record a charge in the financial statements during the period in which any impairment of the goodwill or definite-lived intangible assets is determined, negatively impacting the results of operations. A significant charge could impact the capitalization ratio covenant under certain financing agreements. We are subject to a financial covenant under our credit facilities which requires CPG and the MLP to maintain a total quarterly leverage ratio that does not exceed 5.75 to 1.00 until

December 31, 2015, a ratio of 5.00 to 1.00 until December 31, 2017 and 5.00 to 1.00 for any quarterly period thereafter, with some exceptions. Also, CPG and the MLP are required to maintain a consolidated interest coverage ratio of no less than 3.00 to 1.00. As of March 31, 2015, after giving pro forma effect to the transactions as described under “Capitalization,” our pro forma quarterly leverage ratio would have been 4.50 to 1.00 and our consolidated interest coverage ratio would have been 5.33 to 1.00.

Risks Relating to the Separation

NiSource expects to receive an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution. NiSource’s receipt of the opinion is a condition to the completion of the Distribution. The opinion will be based upon various factual representations and assumptions, as well as certain undertakings made by us and NiSource. If any of those factual representations or assumptions are untrue or incomplete in any material respect, any undertaking is not complied with, or the facts upon which the opinion will be based are materially different from the facts at the time of the Distribution, the Distribution may not qualify for tax-free treatment. Opinions of counsel are not binding on the Internal Revenue Service (“IRS”) or the courts. As a result, the conclusions expressed in an opinion of counsel could be challenged by the IRS, and if the IRS prevails in such challenge, the tax consequences to you could be materially less favorable.

If the Distribution ultimately is determined to be taxable, the Distribution could be treated as a taxable dividend or cause you to recognize taxable capital gain for U.S. federal income tax purposes, and you could incur significant U.S. federal income tax liabilities. In addition, NiSource would recognize gain in an amount equal to the excess of the fair market value of the shares of our common stock distributed to NiSource stockholders on the Distribution Date over NiSource’s tax basis in such shares as of such date.

In addition, under the terms of the Tax Allocation Agreement that we intend to enter into in connection with the Distribution (as described under “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149 of this Information Statement), in the event that the Distribution were determined to be taxable as the result of actions taken after the Distribution by us or any of our subsidiaries, we would be responsible for all taxes imposed on NiSource as a result thereof. In addition, in the event the Distribution were determined to be taxable and neither we nor NiSource were at fault, we would be responsible for a portion of the taxes imposed on NiSource as a result of such determination. Any such tax amounts could be significant.

We may be unable to achieve some or all of the benefits that we expect to achieve as an independent, publicly traded company.

By separating from NiSource there is a risk that we may be more susceptible to market fluctuations and other adverse events than we would have otherwise been while were we still a part of NiSource. As part of NiSource, we were able to enjoy certain benefits from NiSource’s operating diversity, borrowing leverage and available capital for investments, which benefits will no longer be available to us after we separate from NiSource.

We may not be able to achieve the full strategic and financial benefits expected to result from the Separation, or such benefits may be delayed or not occur at all. The Separation is expected to provide benefits, including that:

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the Separation will allow each company to more effectively pursue its own distinct operating priorities and strategies and will enable the management of both companies to pursue separate opportunities for long-term growth and profitability and to recruit, retain and motivate employees pursuant to compensation policies that are appropriate for their respective lines of business;

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the Separation will permit each company to concentrate its financial resources solely on its own operations, providing greater flexibility to invest capital in its business in a time and manner appropriate for its distinct strategy and business needs, all of which will facilitate a more efficient allocation of capital;

•

NiSource’s board of directors believes that NiSource’s businesses and our businesses appeal to different types of investors with different industry focuses, investment goals and risk profiles. NiSource and CPG have different investment and business characteristics, including different opportunities for growth, capital structures, business models and financial returns. The Separation will enable investors to evaluate the merits, performance and future prospects of each company’s businesses and to invest in each company separately based on these distinct characteristics; and

•

the Separation will create an independent equity structure that will afford CPG direct access to capital markets and will facilitate the ability to capitalize on its unique growth opportunities and effect future acquisitions utilizing, among other types of consideration, shares of its common stock. Furthermore, an independent structure should enable each company to provide equity incentive compensation arrangements for its key employees that are directly related to the market performance of each company’s common stock. NiSource’s board of directors believes such equity-based compensation arrangements should provide enhanced incentives for performance and improve the ability for each company to attract, retain and motivate qualified personnel.

We may not be able to achieve some or all of the expected benefits for a variety of reasons. For example, the process of separating our business from NiSource and operating as an independent public company may distract our management from focusing on our business and strategic priorities. In addition, although we will have direct access to the debt and equity capital markets following the Separation, we may not be able to issue debt or equity on terms acceptable to us or at all. The availability of shares of our common stock for use as consideration for acquisitions also will not ensure that we will be able to successfully pursue acquisitions or that the acquisitions will be successful. Following the Separation, we may be more susceptible to market fluctuations and other events particular to one or more of the locations in which we operate than if we were still a part of NiSource, and following the Separation, our business will be less diversified than NiSource’s business prior to the Separation. We also may not fully realize the anticipated benefits from the Separation if any of the matters identified as risks in this “Risk Factors” section were to occur.

The historical and pro forma financial statements included in this Information Statement do not necessarily reflect the results of operations, cash flows and financial condition that we would have achieved as an independent, publicly traded company during the periods presented or those that we will achieve in the future, primarily as a result of the following factors:

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Historically, working capital requirements and capital for the general corporate purposes of CPG’s business, including acquisitions and capital expenditures, have been financed by NiSource. NiSource has historically managed and retained cash we have generated. Following completion of the Separation, NiSource will not be providing us with funds to finance our working capital or other cash requirements. Without the opportunity to obtain financing from NiSource, we may need to obtain additional financing from banks, through public offerings or private placements of debt or equity securities, strategic relationships or other arrangements, and such arrangements may not be available to us or available on terms that are as favorable as those we could have obtained when we were part of NiSource.

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Historically, CPG’s business has been operated by a corporate services subsidiary of NiSource. This entity has historically performed various corporate functions for us, including, but not limited to, tax

administration, treasury activities, accounting, legal, ethics and compliance program administration, investor and public relations, certain governance functions (including internal audit) and external reporting. Our historical and pro forma financial statements reflect allocations of corporate expenses from NiSource for these and similar functions. These allocations may be more or less than the comparable expenses we would have incurred had we operated as an independent, publicly traded company.

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Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operation as a company separate from NiSource.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Our financial results have historically been included within the consolidated results of NiSource, and we believe that our reporting and control systems were appropriate for those of subsidiaries of a public company. However, we are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. As a result of the Distribution, we will be directly subject to reporting and other obligations under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. To comply with the requirements of being a publicly traded company, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff. These reporting and other obligations will place significant demands on our management and administrative and operational resources, including accounting resources. We expect to incur additional annual expenses related to these steps, and those expenses may be significant. If we are unable to upgrade our financial and management controls, reporting systems, information technology systems and procedures in a timely and effective fashion, our ability to comply with our financial reporting requirements and other rules that apply to reporting companies under the Exchange Act could be impaired. If we do not implement such requirements in a timely manner or with adequate compliance, we might be subject to sanctions or investigation by regulatory authorities, such as the SEC or the NYSE. Any such action could harm our reputation and the confidence of our investors and customers and could materially adversely affect our business and cause our share price to fall.

We will incur increased costs as a result of being a publicly traded company.

We have no history operating as a publicly traded company. As a publicly traded company, we will incur legal, accounting and other expenses that we did not incur prior to the Separation. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded company, will reduce the amount of cash we have for the payment of dividends to our stockholders. As a result, the amount of cash we have available for the payment of dividends to our stockholders will be affected by the costs associated with being a public company.

Prior to the Separation, we have not filed reports with the SEC. Following the Separation, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers.

We might not be able to engage in desirable strategic transactions and equity issuances following the Distribution because of certain restrictions relating to requirements for tax-free distributions.

Our ability to engage in significant transactions could be limited or restricted after the Distribution in order to preserve, for U.S. federal income tax purposes, the tax-free nature of the Distribution by NiSource. We will agree to take reasonable action or reasonably refrain from taking action to ensure that the Separation qualifies for tax-free status under Section 355 of the Code. We also will agree to various other covenants in the Tax

Allocation Agreement intended to ensure the tax-free status of the Distribution. These covenants may restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional common stock or other securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. Any acquisitions or issuances of our stock or NiSource’s stock (or any successor thereto) within two years after the Distribution are generally presumed to be related to the Separation, although we or NiSource may be able to rebut that presumption.

To preserve the tax-free treatment to NiSource of the Distribution, under the Tax Allocation Agreement that we will enter into with NiSource, for the two-year period following the Distribution, without obtaining the consent of NiSource, an unqualified opinion of a nationally recognized law firm or a private letter ruling from the IRS, we may be prohibited from:

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approving or allowing issuance of our common stock, except in certain limited circumstances,

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approving or allowing an issuance or sale of equity securities in Columbia Opco that results in our owning less than 55% of the outstanding equity securities of Columbia Opco,

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redeeming equity securities,

•

selling or otherwise disposing of the ownership of the general partner of the MLP or of a specified percentage of our assets or the assets of certain of our subsidiaries, or

•

engaging in certain other transactions that could jeopardize the tax-free status of the Distribution.

These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business. Moreover, the Tax Allocation Agreement will also provide that we are responsible for any taxes imposed on NiSource or any of its affiliates as a result of the failure of the Distribution to qualify for favorable treatment under the Code if such failure is attributable to certain actions taken at any time (even outside the two-year period described above) after the Distribution by or in respect of us or any of our subsidiaries.

We will not have complete control over our tax decisions and could be liable for income taxes owed by NiSource.

For any tax periods (or portion thereof) in which NiSource owns at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries will be included in NiSource’s consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of NiSource or one or more of its subsidiaries for U.S. state or local income tax purposes. See “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149. Moreover, notwithstanding the Tax Allocation Agreement, U.S. federal law provides that each member of a federal consolidated group is liable for the group’s entire federal income tax obligation. Thus, to the extent NiSource or other members of NiSource’s consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of NiSource’s consolidated group. Similar principles may apply for non-U.S., state or local income tax purposes where we file combined, consolidated or unitary returns with NiSource or its subsidiaries for non-U.S., state or local income tax purposes.

The indemnification arrangements we enter into with NiSource in connection with the Separation may require us to divert cash to satisfy indemnification obligations to NiSource and may not be sufficient to cover the full amount of losses for which NiSource indemnifies us.

Pursuant to the Separation and Distribution Agreement and certain other agreements, NiSource will agree to indemnify us from certain liabilities and we will agree to indemnify NiSource for certain liabilities, as discussed further in the sections entitled “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149 of this Information Statement.

A court could deem the Distribution to be a fraudulent conveyance and void the transaction or impose substantial liabilities upon us.

A court could deem the Distribution or certain internal restructuring transactions undertaken by NiSource in connection with the Separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our results of operations, cash flows and financial condition. Among other things, the court could require our stockholders to return to NiSource, for the benefit of its creditors, some or all of the shares of our common stock issued in the Distribution, or require us to fund liabilities of other companies involved in the restructuring transaction. Whether a transaction is a fraudulent conveyance or transfer under applicable state law may vary depending upon the jurisdiction whose law is being applied.

Until the Distribution occurs, NiSource has the sole discretion to change the terms of the Distribution in ways that may be unfavorable to us.

Until the Distribution occurs, NiSource will have the sole and absolute discretion to determine and change the terms of the Distribution, including the establishment of the Record Date and the Distribution Date. These changes could be unfavorable to us. In addition, NiSource may decide at any time prior to the Distribution Date not to proceed with the Distribution.

After the Separation, certain of our directors and officers may have actual or potential conflicts of interest because of their equity ownership in NiSource or the MLP.

Because of their current or former positions with NiSource, following the Separation, certain of our directors and executive officers may own shares of NiSource common stock or rights to acquire shares of NiSource common stock, and the individual holdings may be significant for some of these individuals compared to their total assets. Similarly, certain of our directors and officers hold equity in the MLP. This ownership may create, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for NiSource or the MLP, as applicable, and us. For example, potential conflicts of interest could arise in connection with the resolution of any dispute that may arise between NiSource and us regarding the terms of the agreements governing the Separation and the relationship thereafter between the companies.

The combined value of NiSource and CPG shares after the Separation may not equal or exceed the value of NiSource shares prior to the Separation.

After the Separation, NiSource’s common stock will continue to be listed and traded on the NYSE under the symbol “NI.” We have filed an application to list our common stock on the NYSE under the symbol “CPGX.” We cannot assure you that the combined trading prices of NiSource common stock and our common stock after

the Separation, as adjusted for any changes in the combined capitalization of these companies, will be equal to or greater than the trading price of NiSource common stock prior to the Separation. Until the market has fully evaluated the business of NiSource without our business, the price at which our common stock trades may fluctuate significantly.

Certain administrative services required by us for the operation of our business are currently provided by NiSource Corporate Services Company, a subsidiary of NiSource (“NiSource Corporate Services”), including executive, financial, legal, information technology and other administrative and general services. Prior to the completion of the Separation, we will enter into agreements with NiSource related to the separation of our business operations from NiSource, including the Transition Services Agreements. We believe these steps are necessary to facilitate the efficient operation of our business as we transition to becoming a stand-alone public company. We will, as a result, initially depend on NiSource for services following the completion of the Separation. While these services are being provided to us by NiSource, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of the Transition Services Agreements, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from NiSource under the Transition Services Agreements. Although we intend to replace portions of the services currently provided by NiSource, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” on page 149.

Our agreements with NiSource relating to the Separation require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.

We negotiated all of our agreements with NiSource relating to the Separation as a wholly owned subsidiary of NiSource and will enter into these agreements prior to the completion of the Separation. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the Separation and Distribution Agreement, we will assume all past, present and future liabilities (other than tax liabilities which will be governed by the Tax Allocation Agreement as described further in the section entitled “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation”) related to our business, and we will agree to indemnify NiSource for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between NiSource and us may not reflect the allocation that would have been reached between two unaffiliated parties. In addition, we will have limited remedies under the Separation and Distribution Agreement. See “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” on page 149 for a description of these obligations and the allocation of liabilities between NiSource and us.

Third parties may seek to hold us responsible for liabilities of NiSource that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of NiSource. Under the agreements we intend to enter into with NiSource, NiSource will agree to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from NiSource.

Our prior and continuing relationship with NiSource exposes us to risks attributable to businesses of NiSource.

Under the Separation and Distribution Agreement we intend to enter into with NiSource, NiSource will be obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of NiSource that are incurred through a breach of the Separation and Distribution Agreement or any ancillary agreement by NiSource or its affiliates other than us or our post-Separation affiliates, or losses that are attributable to NiSource in connection with the Separation or are not expressly assumed by us under our agreements with NiSource. Immediately following the Separation, any claims made against us that are properly attributable to NiSource in accordance with these arrangements would require us to exercise our rights under our agreements with NiSource to obtain payment from them. We are exposed to the risk that, in these circumstances, NiSource cannot, or will not, make the required payment.

If in the future we cease to manage and control the MLP through our direct and indirect ownership of the general partner interests in the MLP, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control the MLP and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

Risks Relating to Our Common Stock

There is currently no public market for our common stock. It is anticipated that on or prior to the Record Date for the Distribution, trading of shares of our common stock will begin on a “when-issued” basis and will continue up to and including the Distribution Date. However, there can be no assurance that an active trading market for our common stock will develop as a result of the Distribution or be sustained in the future. The lack of an active trading market may make it more difficult for you to sell shares of our common stock and could lead to our share price being depressed or more volatile.

We cannot predict the prices at which our common stock may trade after the Distribution. The market price of our common stock may fluctuate significantly, depending upon many factors, some of which may be beyond our control, including:

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a shift in our investor base;

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our quarterly or annual earnings, or those of other companies in our industry;

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actual or anticipated fluctuations in our operating results;

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our payment of dividends, if any;

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success or failure of our business strategy;

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our ability to obtain financing as needed;

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changes in accounting standards, policies, guidance, interpretations or principles;

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changes in laws and regulations affecting our business;

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announcements by us or our competitors of significant acquisitions or dispositions;

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the failure of securities analysts to cover our common stock after the Distribution;

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changes in earnings estimates by securities analysts or our ability to meet our earnings guidance;

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the operating and stock price performance of other comparable companies;

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future sales of our common stock; and

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overall market fluctuations and general economic conditions.

Stock markets in general have also experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations could negatively affect the trading price of our common stock.

Substantial sales of common stock may occur in connection with the Distribution, which could cause our stock price to decline.

The shares of our common stock that NiSource distributes to its stockholders generally may be sold immediately in the public market. Although we have no actual knowledge of any plan or intention on the part of any holder of 5% or more of the outstanding shares of NiSource to sell our common stock on or after the Record Date, it is possible that some NiSource stockholders will sell our common stock received in the Distribution for reasons such as our business profile or market capitalization as an independent company not fitting their investment objectives or because our common stock is not included in certain indices after the Distribution. The sales of significant amounts of our common stock or the perception in the market that this will occur may result in the decline of the market price of our common stock.

We may issue additional capital stock, which would dilute your percentage ownership interests.

We may issue additional shares of common stock or issue preferred stock at any time in the future, including as all or part of the consideration paid for acquisitions and strategic investments we may make in the future. Any such issuances may dilute your percentage ownership interests. Additionally, your percentage ownership in us may be diluted in the future because of equity awards that we expect to grant to our directors, officers and employees and because of adjustments being made to outstanding NiSource equity awards in connection with the Separation. We intend to establish equity incentive plans that will provide for the grant of common stock-based equity awards to our directors, officers and employees.

The issuance of additional capital stock may have the following effects:

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our existing stockholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for dividends on a per share of common stock basis may decrease;

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the relative voting strength of each previously outstanding share of capital stock may be diminished;

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the market price of each share of common stock may decline; and

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holders of shares of preferred stock may have separate additional rights, including with respect to dividends, liquidation and voting.

The future payment of dividends will be at the sole discretion of our board of directors and will be dependent on several factors. We cannot guarantee the timing, amount or payment of dividends.

All decisions regarding our payment of dividends will be made by our board of directors from time to time in accordance with applicable law. Although we currently expect to pay cash dividends to our stockholders following the Distribution, there can be no assurance that we will have sufficient surplus under Delaware law to be able to pay any dividends. Our ability to pay dividends in the future will depend upon, among other things, our financial condition, earnings, capital requirements, cash flows and covenants associated with certain of our debt obligations, which may include maintaining certain debt to capital ratios, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Our cash available for dividends will principally be generated by our subsidiaries. Because the cash our subsidiaries generate from operations will fluctuate from quarter to quarter, we may not be able to maintain future dividends at the levels we expect or at all. Our ability to pay dividends depends primarily on cash flows, including cash flows from changes in working capital, and not solely on profitability, which is affected by non-cash items. As a result, we may pay dividends during periods when we record net losses and may be unable to pay cash dividends during periods when we record net income. Moreover, if we determine to pay any dividend in the future, there can be no assurance that we will continue to pay such dividend or the amount of such dividend. For more information, see the section entitled “The Separation—Dividends” on page 72.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our Company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which will limit our stockholders’ ability to choose the judicial forum for disputes with us or our directors, officers or other employees.

Our amended and restated certificate of incorporation will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or other employees arising pursuant to any provision of the Delaware General Corporation Law, as amended (the “DGCL”), our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us or any of our directors, officers or other employees governed by the internal affairs doctrine of the State of Delaware. By purchasing or otherwise acquiring any interest in shares of our capital stock, a stockholder is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our directors and officers.

Section 203 of the DGCL and provisions in our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire us without the consent of our board of directors. See “Description of Capital Stock—Certain Provisions of Delaware Law, Our Charter and Our Bylaws” on page 156. These provisions include the following:

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the right of our board of directors to issue preferred stock without stockholder approval;

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a classified board of directors;

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no cumulative voting;

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the inability of our stockholders to call a special meeting or act by written consent;

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rules regarding how stockholders may present proposals or nominate directors for election at stockholder meetings;

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a provision that stockholders may only remove directors for cause;

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the establishment in our certificate of incorporation of the maximum number of directors that constitutes our board;

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the ability of our directors, and not stockholders, to fill vacancies (including those resulting from an enlargement of the board of directors) on our board of directors;

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the requirement that stockholders holding at least 80% of our voting stock are required to amend certain provisions of our organizational documents; and

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restrictions on business combinations for a three-year period with a stockholder who becomes the beneficial owner of more than 15% of our common stock without prior board approval.

Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our direction or our management may be unsuccessful.

CAUTIONARY NOTE CONCERNING FORWARD-LOOKING STATEMENTS

This Information Statement contains forward-looking statements. Forward-looking statements give our current expectations and contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “will,” “should,” “would,” “could,” “budget,” “potential,” or “continue” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Information Statement. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

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changes in general economic conditions;

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competitive conditions in our industry;

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actions taken by third-party operators, processors and transporters;

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the demand for natural gas storage and transportation services;

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the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

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competition from the same and alternative energy sources;

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our ability to successfully implement our business plan;

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our ability to complete internal growth projects on time and on budget;

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the price and availability of debt and equity financing;

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restrictions in our existing and any future credit facilities;

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capital market performance and other factors that may decrease the value of benefit plan assets;

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the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

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competition from the same and alternative energy sources;

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energy efficiency and technology trends;

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operating hazards and other risks incidental to transporting, storing and gathering natural gas;

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natural disasters, weather-related delays, casualty losses and other matters beyond our control;

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interest rates;

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labor relations;

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large customer defaults;

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changes in the availability and cost of capital;

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changes in tax status;

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the effects of existing and future laws and governmental regulations;

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the effects of future litigation;

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the qualification of the Separation as a tax-free Distribution;

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our ability to achieve the benefits that we expect to achieve as an independent publicly traded company;

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our dependence on NiSource to provide us with certain services following the Separation; and

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certain factors discussed elsewhere in this Information Statement.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. The forward-looking statements included in this document are made as of the date of this Information Statement. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to future results over time or otherwise, except as required by law.

THE SEPARATION

Background

On June 2, 2015, NiSource announced that its board of directors had approved the distribution of our common stock to holders of NiSource common stock as of the Record Date. On the Distribution Date, holders of NiSource common stock will receive one share of our common stock for each share of NiSource common stock held at 5:00 p.m., Central Time, on the Record Date. Stockholders who are entitled to receive shares of our common stock in the Distribution will not be required to pay any cash or deliver any other consideration, including any shares of NiSource common stock, to receive shares of our common stock in the Distribution.

The Distribution as described in this Information Statement is subject to the satisfaction or waiver of certain conditions. We cannot provide any assurances that the Distribution will be completed. For a more detailed description of these conditions, see the caption entitled “Conditions to the Distribution” beginning on page 71 of this Information Statement.

Corporate Structure

The following is a simplified diagram of our ownership structure, including key operating subsidiaries immediately following the Separation:

LOGO

Reasons for the Separation

A wide variety of factors were considered by the NiSource board of directors in evaluating the Separation. Among other things, the NiSource board of directors considered the following potential benefits of the Separation:

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Independent Equity Structure—The Separation will create an independent equity structure that will afford CPG direct access to capital markets and will facilitate the ability to capitalize on its unique growth opportunities and effect future acquisitions utilizing, among other types of consideration, shares of its common stock. Furthermore, an independent structure should enable each company to provide equity incentive compensation arrangements for its key employees that are directly related to the market performance of each company’s common stock. NiSource’s board of directors believes such equity-based compensation arrangements should provide enhanced incentives for performance and improve the ability for each company to attract, retain and motivate qualified personnel.

Our Subsidiary the MLP

Columbia OpCo using debt and equity financing, and to the extent the MLP acquires additional interests in Columbia OpCo, we will have more cash available to execute our growth strategy. Additionally, the MLP has a $500 million credit facility. These additional sources of financing should assist us in funding our organic capital investment projects and third-party acquisitions as needed.

When and How You Will Receive CPG Shares

NiSource will distribute to its stockholders, on a one-to-one basis, all of the shares of our common stock on the Distribution Date to holders of NiSource common stock as of the Record Date. Computershare will serve as transfer agent and registrar for our common stock and as distribution agent in connection with the Distribution. If you are entitled to receive shares of our common stock in the Distribution, the common stock will be issued to your account as follows:

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Registered stockholders. If you own your shares of NiSource common stock directly, either through an account with Computershare or if you hold paper stock certificates, you will receive your shares of our common stock by way of direct registration in book-entry form. Registration in book-entry form refers to a method of recording share ownership where no physical share certificates are issued to stockholders, as is the case in the Distribution.

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“Street name” or beneficial stockholders. Most NiSource stockholders hold their shares of NiSource common stock beneficially through a broker, bank or other nominee. In such cases, the broker, bank or other nominee is said to hold the stock in “street name,” and ownership is recorded on the books of the bank, broker or other nominee. If you hold your NiSource common stock through a bank, broker or other nominee, your bank, broker or other nominee will credit your account with the shares of our common stock that you are entitled to receive in the Distribution. If you have any questions concerning the mechanics of having shares of common stock held in “street name,” we encourage you to contact your broker, bank or other nominee.

Holders of NiSource common stock are not being asked to take any action in connection with the Separation or the Distribution. No stockholder approval of the Separation or the Distribution is required or is being sought. We are not asking you for a proxy, and we request that you not send us a proxy. You are also not being asked to surrender any of your shares of NiSource common stock for shares of our common stock. The number of outstanding shares of NiSource common stock will not change as a result of the Distribution.

Number of Shares You Will Receive

Common shares

On the Distribution Date, NiSource will distribute one share of our common stock for each share of NiSource common stock outstanding as of the Record Date.

Fractional shares

NiSource stockholders will not receive fractional shares of our common stock in the Distribution. Instead, all fractional shares of our common stock will be aggregated into whole shares and sold in the open market at prevailing market prices by the Distribution Agent. The Distribution Agent will then distribute the aggregate cash proceeds of the sales, net of brokerage fees and other costs, pro rata to both registered holders and beneficial holders who would otherwise have been entitled to receive a fractional share of our common stock in the Distribution. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payments made in lieu of fractional shares. The receipt of cash in lieu of fractional shares generally will be taxable to the recipient stockholders as described in the section “The Separation—Material U.S. Federal Income Tax Consequences of the Separation” beginning on page 67 of this Information Statement.

Preferred shares

No shares of our preferred stock will be distributed with respect to any outstanding shares of NiSource common stock.

Treatment of Equity-Based Compensation

The following discussion describes the expected treatment of NiSource equity awards in connection with the Separation. The different types of awards listed below are described in further detail in the Compensation Discussion and Analysis section of this Information Statement, beginning on page 111. The post-Separation treatment of a person’s award is expected to depend on the type of award and whether the person will be an employee of NiSource or CPG immediately following the Separation. For purposes of this discussion, a “NiSource Holder” refers to an individual who is an employee or nonemployee director of NiSource immediately following the Separation, and a “CPG Holder” refers to an individual who is an employee or nonemployee director of CPG immediately following the Separation, regardless of the entity for which such individual provided services immediately prior to the Separation. We expect that the treatment described below would become effective as of the Distribution Date.

Restricted Stock Units

We expect the treatment of NiSource RSUs that are outstanding on the Distribution Date to depend on the status of the holder. We expect that NiSource RSUs held on the Distribution Date by any employee of CPG immediately following the Separation and unvested NiSource RSUs held by any non-employee director of CPG immediately following the Separation will convert into CPG RSUs in a manner that preserves the value of the award following the Separation. We expect that NiSource RSUs held on the Distribution Date by any employee of NiSource immediately following the Separation and unvested NiSource RSUs held by any non-employee director of NiSource immediately following the Separation will be adjusted to preserve the value of the award following the Separation. We also expect that vested NiSource RSUs held by any individual who is a non-employee director of either CPG or NiSource immediately following the Separation will be retained and such non-employee director will also receive CPG RSUs equal to the number of shares of CPG stock that such non-employee director would have received if such non-employee director owned the shares subject to the vested NiSource RSUs on the Distribution Date. After the Distribution Date, the NiSource RSUs and CPG RSUs will be subject to substantially the same terms and conditions as the original NiSource RSUs, except that the vesting of awards held by CPG Holders will be based on continued service with CPG.

Performance Share Awards

Similarly, we expect the treatment of NiSource PSAs that are outstanding on the Distribution Date to be adjusted or converted into CPG awards in a manner that preserves the intended value of such awards following the Separation. The treatment of outstanding NiSource PSAs will depend on the status of the holder as of the Distribution Date and the year in which the award was granted.

NiSource PSAs held by CPG Holders

shares of NiSource common stock that are deemed to have been earned as of the Distribution Date will be equal to 50% of the target number of shares subject to such award. With respect to the remaining 50% of such NiSource PSA, the number of shares of NiSource common stock earned will be based on actual performance results through the Distribution Date. The number of such NiSource shares that are earned or deemed to have been earned will then be converted into substitute CPG RSUs in a manner that preserves the value of the award following the Separation. Such substitute CPG RSUs will vest on the last day of the performance period to which they relate based on the holder’s service with CPG and will have the same terms and conditions as the corresponding NiSource PSA, except as otherwise described herein.

NiSource PSAs held by NiSource Holders

2013 Awards. We expect that each NiSource PSA granted in 2013 and held by a NiSource Holder on the Distribution Date will be adjusted in a manner that preserves the value of the award following the Separation. The number of shares of NiSource common stock earned pursuant to the NiSource PSA will be based on actual performance results through the Distribution Date. The number of such NiSource shares that are earned will then be adjusted in a manner that preserves the value of the award following the Separation. Each adjusted award will vest on the last day of the performance period to which it relates based on the holder’s continued service with NiSource and will have the same terms and conditions as currently effect, except as otherwise described herein.

Payments to NiSource and Its Directors and Executive Officers in Connection with the Separation

Prior to the Separation, CPG plans to pay to NiSource a special dividend of $1,450.0 million. To the extent that NiSource directors and executive officers hold NiSource common stock as of the Record Date, such directors and officers will receive shares of CPG common stock on the Distribution Date on a one-to-one basis, in the same manner as all of the other NiSource stockholders. For information regarding the beneficial ownership of NiSource common stock of NiSource directors and officers, see NiSource’s definitive proxy statement relating to its 2015 annual meeting of stockholders, filed with the SEC on April 7, 2015. The expected treatment of NiSource equity-based compensation awards in connection with the Separation is described in the immediately preceding paragraphs under the heading “Treatment of Equity-Based Compensation.”

In connection with the Separation, the Human Resources and Compensation Committee of the CPG board of directors is expected to approve a grant of performance-based equity awards to select CPG executives, including each of the Named Executive Officers, to be made following the Distribution Date. These awards are designed to provide executive alignment with post-Separation CPG stockholders and reward participants for long-term growth in CPG’s stock price. It is currently anticipated that these performance-based awards will vest based on a relative total shareholder return measure over a three-year performance period.

The Human Resources and Compensation Committee of the CPG board of directors is expected to approve a target dollar value for each participant, and the target dollar values will be converted into a specific number of shares or units based on the CPG closing stock price on the first full day of trading following the Distribution Date. Each of the Named Executive Officers is expected to receive a target award value in an amount of up to $2 million.

Transferability of Shares You Receive

The shares of our common stock distributed to NiSource stockholders will be freely transferable, except for shares received by persons who may be deemed to be our “affiliates” under the Securities Act of 1933, as amended (the “Securities Act”). Persons who may be deemed to be our affiliates after the Separation generally include individuals or entities that control, are controlled by or are under common control with us and may include directors and certain officers or principal stockholders of CPG. Our affiliates will be permitted to sell their shares of our common stock only pursuant to an effective registration statement under the Securities Act or an exemption from the registration requirements of the Securities Act, such as the exemptions afforded by Rule 144.

Material U.S. Federal Income Tax Consequences of the Separation

The following is a summary of the material U.S. federal income tax consequences to NiSource and to the holders of shares of NiSource common stock in connection with the Separation. This summary is based on the Code, the Treasury Regulations promulgated thereunder and judicial and administrative interpretations thereof, in each case as in effect and available as of the date of this Information Statement and all of which are subject to change at any time, possibly with retroactive effect. Any such change could affect the tax consequences described below.

This summary is limited to holders of shares of NiSource common stock that are U.S. Holders, as defined immediately below. A “U.S. Holder” is a beneficial owner of NiSource common stock that is, for U.S. federal income tax purposes:

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an individual citizen or a resident of the United States;

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a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, created or organized under the laws of the United States or any state thereof or the District of Columbia;

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an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

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a trust, if (i) a court within the United States is able to exercise primary jurisdiction over its administration and one or more United States persons have the authority to control all of its substantial decisions or (ii) in the case of a trust that was treated as a domestic trust under the law in effect before 1997, a valid election is in place under applicable Treasury Regulations.

This summary also does not discuss all tax considerations that may be relevant to stockholders in light of their particular circumstances, nor does it address the consequences to stockholders subject to special treatment under U.S. federal income tax law, such as:

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dealers or brokers in securities or currencies;

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traders in securities who elect to apply a mark-to-market method of accounting;

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tax-exempt entities;

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banks, financial institutions or insurance companies;

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mutual funds;

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regulated investment companies and real estate investment trusts;

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a corporation that accumulates earnings to avoid U.S. federal income tax;

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holders who hold individual retirement or other tax-deferred accounts;

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persons who acquired shares of NiSource common stock pursuant to the exercise of employee stock options or otherwise as compensation;

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stockholders who own, or are deemed to own, at least 10% or more, by voting power or value, of NiSource equity;

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holders owning NiSource common stock as part of a position in a straddle or as part of a hedging, conversion or other risk reduction transaction for U.S. federal income tax purposes;

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holders who have a functional currency other than the U.S. dollar;

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certain former citizens or long-term residents of the United States;

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holders who are subject to the alternative minimum tax; or

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persons who own NiSource common stock through partnerships or other pass-through entities.

This summary does not address the U.S. federal income tax consequences to NiSource stockholders who do not hold shares of NiSource common stock as a capital asset. Moreover, this summary does not address any state, local or non-U.S. tax consequences or any estate, gift or other non-income tax consequences.

If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds shares of NiSource common stock, the tax treatment of a partner in that partnership will generally depend on the status of the partner and the activities of the partnership. Such a partner or partnership should consult its own tax advisor as to the tax consequences of the Distribution.

YOU SHOULD CONSULT YOUR OWN TAX ADVISOR WITH RESPECT TO THE U.S. FEDERAL, STATE AND LOCAL AND NON-U.S. TAX CONSEQUENCES OF THE DISTRIBUTION.

General

NiSource has requested an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution under Section 355 of the Code. The receipt by NiSource of the opinion is a condition to the Distribution.

Assuming the Distribution qualifies for tax-free treatment under Section 355 of the Code, for U.S. federal income tax purposes:

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no gain or loss will be recognized by NiSource as a result of the Distribution, except with respect to any “excess loss account” or “intercompany transaction” required to be taken into account under Treasury Regulations relating to consolidated returns;

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no gain or loss will be recognized by, or be includible in the income of, a holder of NiSource common stock, solely as a result of the receipt of our common stock in the Distribution, except with respect to any cash received in lieu of fractional shares;

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the aggregate tax basis of the shares of NiSource common stock and the shares of our common stock in the hands of NiSource stockholders immediately after the Distribution will be the same as the aggregate tax basis of the shares of NiSource common stock held by the holder immediately before the Distribution, allocated between the shares of NiSource common stock and shares of our common stock, including any fractional share interest for which cash is received, in proportion to their relative fair market values immediately following the Distribution;

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the holding period with respect to shares of our common stock received by NiSource stockholders will include the holding period of their shares of NiSource common stock, provided that such shares of NiSource common stock are held as a capital asset; and

•

a NiSource stockholder who receives cash in lieu of a fractional share of our common stock in the Distribution will be treated as having sold such fractional share for cash and generally will recognize capital gain or loss in an amount equal to the difference between the amount of cash received and such stockholder’s adjusted tax basis in the fractional share. That gain or loss will be long-term capital gain or loss if the stockholder’s holding period for its shares of NiSource common stock exceeds one year.

An opinion of counsel represents counsel’s best legal judgment but is not binding on the IRS or any court. The opinion will be based upon various factual representations and assumptions, as well as certain undertakings made by us and NiSource. If any of those factual representations or assumptions are untrue or incomplete in any material respect, any undertaking is not complied with, or the facts upon which the opinion will be based are materially different from the facts at the time of the Distribution, the Distribution may not qualify for tax-free treatment. If, on audit, the IRS were successful in asserting that the Distribution is taxable, the above consequences would not apply and both NiSource and its stockholders could be subject to tax.

If, notwithstanding the conclusions that we expect to be included in the opinion, it is ultimately determined that the Distribution does not qualify as tax-free for U.S. federal income tax purposes, then NiSource would recognize gain in an amount equal to the excess of the fair market value of our common stock distributed to NiSource stockholders on the Distribution Date over NiSource’s tax basis in such shares.

In addition, if the Distribution were not to qualify as tax-free for U.S. federal income tax purposes, each U.S. Holder who receives shares of our common stock in the Distribution could be treated as receiving a distribution in an amount equal to the fair market value of our common stock that was distributed to the stockholder, which generally would be taxed as a dividend to the extent of the stockholder’s pro rata share of NiSource’s current and accumulated earnings and profits and then treated as a non-taxable return of capital to the extent of the stockholder’s basis in the NiSource stock and finally as capital gain from the sale or exchange of NiSource stock.

Even if the Distribution otherwise qualifies for tax-free treatment under Section 355 of the Code, it may result in corporate level taxable gain to NiSource under Section 355(e) of the Code if 50% or more, by vote or value, of our stock or NiSource’s stock (or any successor to us or NiSource) is acquired or issued (or is deemed to be acquired or issued) as part of a plan or series of related transactions that includes the Distribution. For this purpose, any acquisitions or issuances of NiSource’s stock within two years before the Distribution, and any acquisitions or issuances of our stock or NiSource stock within two years after the Distribution are generally presumed to be part of such a plan, although we or NiSource may be able to rebut that presumption. If an acquisition or issuance of our stock or NiSource stock (or any successor) triggers the application of Section 355(e) of the Code, NiSource would recognize taxable gain as described above and such gain would be subject to U.S. federal income tax.

Information Reporting and Backup Withholding

Treasury Regulations require certain stockholders who receive stock in a distribution to attach to their U.S. federal income tax return for the year in which the distribution occurs a detailed statement setting forth certain information relating to the tax-free nature of the distribution. Within a reasonable period after the Distribution, we will provide stockholders who receive our common stock in the Distribution with the information necessary to comply with such requirement. In addition, all U.S. Holders are required to retain permanent records relating to the amount, basis and fair market value of our common stock received in the Distribution and to make those records available to the IRS upon request.

In addition, payments of cash to a U.S. Holder of NiSource common stock in lieu of fractional shares of our common stock in the Distribution may be subject to information reporting and backup withholding (currently at a rate of 28%), unless the stockholder provides proof of an applicable exemption or a correct taxpayer identification number and otherwise complies with the requirements of the backup withholding rules. Backup withholding does not constitute an additional tax, but is merely an advance payment, which may be refunded or credited against a stockholder’s U.S. federal income tax liability, provided the required information is timely supplied to the IRS.

Market for Our Common Stock

There is currently no public market for our common stock. A condition to the Distribution is the listing of our common stock on the NYSE. We are in the process of applying to list our common stock on the NYSE and expect to list under the ticker symbol “CPGX.”

Beginning on or shortly before the Record Date and continuing up to and including the Distribution Date, we expect that there will be a when-issued market in our common stock. “When-issued trading” refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The “when-issued trading” market will be a market for shares of our common stock that will be distributed to NiSource stockholders on the Distribution Date. If you own shares of NiSource common stock as of the Record Date, you will be entitled to shares of our common stock distributed pursuant to the Distribution. You may trade this entitlement to shares of our common stock, without trading the shares of NiSource common stock you own, on the when-issued market. On the first trading day following the Distribution Date, when-issued trading with respect to our common stock will end and regular way trading will begin. “Regular way” trading refers to trading after a security has been issued and typically involves a transaction that settles on the third full business day following the date of the transaction.

Trading of Common Stock after the Record Date and Prior to the Distribution

Beginning on or shortly before the Record Date and continuing up to and including the Distribution Date, we expect that there will be two markets in NiSource common stock: a “regular way” market and an ex-distribution market. Shares of NiSource common stock that trade on the regular way market will trade with an entitlement to receive shares of our common stock distributed pursuant to the Distribution. Shares that trade on the ex-distribution market will trade without an entitlement to receive shares of our common stock distributed pursuant to the Distribution. Therefore, if you sell shares of NiSource common stock in the regular way market after 5:00 p.m., Central Time, on the Record Date and up to and including the Distribution Date, you will be selling your right to receive shares of our common stock in the Distribution. If you own shares of NiSource common stock at 5:00 p.m., Central Time, on the Record Date and sell those shares on the ex-distribution market, up to and including the Distribution Date, you will still receive the shares of our common stock that you would be entitled to receive pursuant to your ownership of the shares of NiSource common stock.

Results of the Separation

After the Separation we will be an independent, publicly traded company. Immediately following the Distribution, we expect to have approximately 24,652 stockholders of record, based on the number of registered stockholders of NiSource common stock on May 28, 2015, and approximately 317,535,860 shares of our common stock outstanding. The actual number of shares to be distributed will be determined on the Record Date and will reflect any exercise of NiSource options and the vesting of NiSource RSUs or performance shares at any time prior to the Record Date.

We will enter into a Separation and Distribution Agreement and several other agreements with NiSource to effect the Separation and Distribution and provide a framework for our relationship with NiSource after the Separation. Shortly before the Distribution, we and NiSource will also enter into Transition Services Agreements, an Employee Matters Agreement, a Tax Allocation Agreement, a Trademark License Agreement and certain other agreements. We cannot assure you that these agreements are or will be on terms as favorable to us or to NiSource as agreements with unaffiliated third parties. For more information, see the section entitled “Certain Relationships and Related Party Transactions—Agreements with NiSource Relating to the Separation” beginning on page 149 of this Information Statement.

Additionally, CPG has entered into certain operating and maintenance agreements with NiSource which will remain in place following the Separation, all of which have been and are expected to be subject to applicable regulatory approval.

The Distribution will not affect the number of outstanding shares of NiSource common stock or any rights of holders of NiSource common stock.

Conditions to the Distribution

We expect that the Separation will be effective on the Distribution Date, provided that the following conditions have been satisfied or waived by NiSource:

•

the board of directors of NiSource has authorized and approved the transactions contemplated by the Separation and Distribution Agreement, including the Distribution;

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NiSource has contributed to CPG all of NiSource’s right, title and interest in certain assets related to CPG’s business;

•

the senior notes offering discussed elsewhere in this Information Statement has been consummated and the special dividend to NiSource discussed elsewhere in this Information Statement has been paid;

•

NiSource is satisfied that no NiSource party has any liability under the CPG financing transactions that occur prior to the Distribution Date and NiSource has entered into a new credit facility;

•

NiSource and CPG have entered into certain conveyancing instruments and the Tax Allocation Agreement, the Employee Matters Agreement, the Transition Services Agreements and the Trademark License Agreement;

•

the SEC has declared effective our registration statement on Form 10, of which this Information Statement is a part, under the Exchange Act, and no stop order suspending the effectiveness of our registration statement on Form 10 is in effect or, to the knowledge of NiSource or CPG, threatened by the SEC;

•

NiSource has mailed this Information Statement to the holders of record of NiSource common stock;

•

NiSource and CPG have received all permits, registrations and consents required under the securities or “blue sky” laws of states or other political subdivisions of the United States or of applicable foreign jurisdictions in connection with the Distribution;

•

the NYSE has approved our common stock for listing, including shares to be issued under our long-term incentive plan, subject to official notice of issuance;

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NiSource has received an opinion of Sidley Austin LLP, counsel to NiSource (or other nationally recognized tax counsel), in form and substance satisfactory to NiSource, confirming the tax-free status of the Distribution for U.S. federal income tax purposes;

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an independent financial advisory firm acceptable to NiSource, in its sole and absolute discretion, has delivered an opinion to NiSource confirming the solvency and adequacy of capital of CPG and NiSource, and such opinions have not been withdrawn or rescinded;

•

NiSource and CPG have received all material permits, registrations, clearances, approvals and consents from governmental authorities and third persons necessary to effect the Distribution and to permit the operation of our business after the Distribution Date;

•

no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the Distribution is in effect;

•

NiSource and CPG have each received credit ratings from the credit rating agencies that are satisfactory to NiSource; and

•

no event or development has occurred or exists that, in the judgment of the NiSource board of directors, in its sole and absolute discretion, makes it inadvisable to effect the Distribution or any of the other transactions contemplated by the Separation and Distribution Agreement.

The fulfillment of the foregoing conditions will not create any obligation on the part of NiSource to effect the Distribution, and the board of directors of NiSource may terminate the Separation and Distribution Agreement and the Distribution at any time prior to the Distribution. The board of directors of NiSource may waive any of these conditions in its sole and absolute discretion.

Dividends

Following the Separation, we expect to establish a dividend payout ratio target, which reflects the percentage of our recurring earnings expected to be paid as dividends. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements, cash flows, covenants associated with certain of our debt obligations, which may include maintaining certain debt to capital ratios, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend in the future, there can be no assurance that we will continue to pay such dividends or the amount of such dividends.

Reasons for Furnishing This Information Statement

This Information Statement is being furnished solely to provide information to NiSource stockholders who are entitled to receive shares of our common stock in the Distribution. This Information Statement is not, and is not to be construed as, an inducement or encouragement to buy, hold or sell any of our securities. We believe that the information in this Information Statement is accurate as of the date indicated on the cover page. Changes may occur after that date, and neither NiSource nor CPG undertakes any obligation to update such information except pursuant to our respective obligations under the securities laws.

CAPITALIZATION

The following table presents CPG’s cash and cash equivalents and capitalization as of March 31, 2015 and our unaudited pro forma cash and cash equivalents and capitalization as of that date reflecting the following transactions as if they had occurred on March 31, 2015:

•

Distribution Adjustments—reflect the issuance of shares of CPG common stock so that shares issued equals the number of shares of NiSource common stock outstanding on the Record Date and the elimination of NiSource’s net investment in CPG.

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Financing Adjustments—reflect the issuance of $2,750.0 million of debt securities and receipt of approximately $2,721.0 million of cash. Prior to the Distribution, CPG expects to use the proceeds of the debt offering to repay $1,025.2 million of intercompany debt between CPG and NiSource and make a cash distribution of $1,450.0 million to NiSource.

The pro forma adjustments are based on available information and assumptions that management believes are reasonable. However, such adjustments are subject to change based on the finalization of the terms of the Distribution and the agreements that define our relationship with NiSource after the Distribution. In addition, such adjustments are estimates and may not prove to be accurate.

The information in the following table is derived from, and should be read together with, our unaudited pro forma consolidated financial statements and the accompanying notes and CPG’s unaudited consolidated and combined financial statements and the accompanying notes included elsewhere in this Information Statement. You should also read the information in the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of March 31, 2015
	CPG Historical		Pro Forma
	(in millions)
Cash and cash equivalents	$	7.3	$	253.1

Capitalization:
Indebtedness (net):
Long-term debt^(a)	$	—	$	2,746.0
Long-term debt—affiliated		1,848.2		—

Total indebtedness (net)		1,848.2		2,746.0
Equity:
Net parent investment		4,027.9		—
Common stock^(b)		—		3.2
Additional paid-in capital		—		2,574.7
Accumulated other comprehensive loss		(25.1)		(25.1)
Non-controlling interest^(c)		946.2		946.2

Total equity		4,949.0		3,499.0

Total capitalization	$	6,797.2	$	6,245.0

(a)	Net of issue discount of approximately $4.0 million, which will be amortized over the life of our senior unsecured notes issued on May 22, 2015.

(b)	The pro forma number of shares of CPG common stock issued will be equal to the number of shares of NiSource common stock outstanding on the Record Date.

(c)	Reflects the 8.4% non-controlling interest held by the public in the MLP.

BUSINESS

Overview

We are a growth-oriented Delaware corporation formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets.

We own approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2014, 94% of our revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years. We own these assets through Columbia OpCo, a partnership between our wholly owned subsidiary CEG and the MLP.

The following is a summary of the locations and timing of our modernization program and planned growth projects:

LOGO

(1)	The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) is expected to be placed in service in the third quarter of 2015.

(2)	The Phase II gathering and compression portion of Washington County Gathering (approximately $56 million in capital costs) is expected to be placed in service in the third quarter of 2018.

Business Strategies

Permit the MLP to further invest in organic growth projects. We expect Columbia OpCo to issue a significant amount of new limited partnership interests over the next several years to fund approximately $5.0 billion in estimated capital costs for organic growth projects that we expect will be completed by the end of 2018, and we expect that the MLP will exercise its preemptive right to purchase these newly issued equity interests to the extent financing is available. The MLP also has a right of first offer with respect to acquiring CEG’s retained 84.3% limited partnership interest in Columbia OpCo if CEG decides to sell such interest. We do not expect to sell CEG’s retained limited partnership interest in Columbia OpCo in the near term.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

and the marketplace. In addition, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers’ demand for natural gas. We believe the integrated nature of our operations and the broad range of services we provide to customers allows us to compete effectively with other pipeline, storage and midstream companies that operate in our marketplace.

Stable and predictable cash flows. We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices. For the year ended December 31, 2014, approximately 94% of our revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years. Furthermore, a significant portion of our cash flows are generated from contracts with creditworthy customers including LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters.

Our Subsidiary the MLP

Our Operations and Operating Assets

Our assets include interstate pipelines and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. Our network of interstate pipelines extends from New York to the Gulf of Mexico, serving customers in 15 northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia.

The transportation and storage rates and services of our interstate natural gas pipeline and storage assets are subject to regulation by the FERC, which reviews and approves the tariff that establishes our rates, cost recovery mechanisms and terms and conditions of service. The rates established under our tariffs are a function of each jurisdictional company’s costs of providing services to customers, including a reasonable rate of return on invested capital. The FERC has jurisdiction over, among other things, the construction and operation of facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities. The FERC also has jurisdiction over the rates, terms, and conditions for the transportation and storage of natural gas in interstate commerce. All of our interstate pipeline transportation rates and storage rates and terms of service are regulated by the FERC.

Additionally, we manage mineral rights and own and operate gathering pipelines, certain of which are regulated by the FERC, and processing facilities.

Columbia Gas Transmission

Columbia Gas Transmission owns and operates a FERC-regulated interstate natural gas transportation pipeline and storage system, which consists of approximately 11,400 miles of natural gas transmission pipeline and 89 compressor stations with 635,671 horsepower of installed capacity. Columbia Gas Transmission has a transportation capacity of approximately 10 MMDth/d, transports an average of approximately 3.8 MMDth/d, and has experienced peak day deliveries of approximately 7.9 MMDth/d. Columbia Gas Transmission serves hundreds of communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission also owns and operates one of North America’s largest underground natural gas storage systems, which includes 34 storage fields in four states with approximately 622 MMDth in total capacity, with approximately 290 MMDth of working gas capacity.

Columbia Gas Transmission has historically largely operated as a means to transport gas from the Gulf Coast, via Columbia Gulf, from various pipeline interconnects, and from production areas in the Appalachia region to markets in the Midwest, mid-Atlantic, and northeast regions. As Marcellus and Utica shale gas production has grown, Columbia Gas Transmission’s operations and assets also have grown due to the increased production within the pipeline’s operating area. As the market continues to evolve, Columbia Gas Transmission is in various phases of execution and construction on a multitude of growth projects to help move the growing production of gas out of the Marcellus and Utica shale areas and into on-system markets in the northeast and mid-Atlantic markets as well as off-system markets in the Gulf Coast.

Columbia Gas Transmission plays a key role in transporting the growing supply of Marcellus and Utica gas being produced in the area. The pipeline is a highly reticulated system that operates in a variety of market areas and depends on several of its major backbone systems to transport gas throughout its service area:

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R System. The R System connects the Ohio markets with Columbia Gas Transmission’s interconnect with Columbia Gulf at Leach, Kentucky.

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T System. The T System connects Broad Run in West Virginia with the Pittsburgh market area in western Pennsylvania.

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WB/VB Systems. The WB and VB Systems connect Broad Run in West Virginia to the Eastern market, directly into the Washington, D.C. and Baltimore markets.

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KA/VA Systems. The KA and VA Systems connect Appalachian production in West Virginia and Kentucky to the Eastern market, directly into the Washington, D.C. and Baltimore markets.

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VM System. The VM System connects the WB, VB and VA Systems with the southeastern Virginia markets, Columbia Gas Transmission’s Chesapeake LNG peaking facility, and interconnects with Transcontinental Gas Pipeline Company in southeast Virginia.

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1278 System. The 1278 system connects the WB and VB Systems with the Philadelphia, New Jersey, and New York markets as well as with interconnects with Millennium Pipeline at the Wagoner compressor station in eastern New York.

The system is connected to approximately 1,196 natural gas receipt points and approximately 1,691 natural gas delivery points. Additionally, Columbia Gas Transmission has a highly liquid trading pool, commonly referred to as “TCO Pool,” which provides pricing transparency for significant quantities of traded supply for producers, marketers, and downstream users across the system.

LOGO

Customers. Columbia Gas Transmission transports natural gas for a broad mix of customers, including LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. In addition to serving markets directly connected to its system, Columbia Gas Transmission serves markets and customers in a variety of other regions through numerous interconnections with third-party interstate and intrastate pipelines.

As of December 31, 2014, Columbia Gas Transmission had 215 firm contract customers. Its three largest customers for the year ended December 31, 2014 were Columbia Gas of Ohio, Washington Gas Light Company and Columbia Gas of Pennsylvania. Contracts with these three customers accounted for approximately 18%, 11% and 6% of Columbia Gas Transmission’s contracted revenues, respectively, during 2014, although each of these customers contracted a portion of their reserved capacity to third parties that paid Columbia Gas Transmission directly for the subcontracted amounts. For the twelve months ended December 31, 2014, Columbia Gas Transmission’s top 25 largest non-affiliated customers measured by contracted revenues generated approximately 51% of Columbia Gas Transmission’s transportation revenue.

Contracts. Under transportation agreements governed by its FERC-approved natural gas tariff, Columbia Gas Transmission offers its customers firm and interruptible transportation and storage services. For the twelve months ended December 31, 2014, approximately 99% of Columbia Gas Transmission’s transportation and storage revenues were derived from firm contracts and approximately 1% were derived from interruptible contracts.

The table below sets forth certain information regarding Columbia Gas Transmission as of December 31, 2014:


	Total Firm Contracted Capacity⁽¹⁾		Weighted Average Remaining Firm Contract Life⁽²⁾
Transportation		9.3 MMDth/d		5.5 years
Storage		252.0 MMDth		3.0 years

(1)	Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation or storage capacity regardless of the actual amount of transportation or storage capacity used by the customer during each month.

(2)	Weighted by contracted capacity.

Tariff Rates. Columbia Gas Transmission’s maximum and minimum recourse rates for its transportation services are governed by its FERC-approved natural gas tariff. Terms and conditions for service under this tariff are based on firm capacity reservation charges and both firm and interruptible usage fees for transportation across its system. As of December 31, 2014, the rates in effect for 82% of Columbia Gas Transmission’s firm contracts were at the maximum recourse rates prescribed for in its tariff.

In 1996, Columbia Gas Transmission entered into a rate settlement with its customers which established new base rates under Columbia Gas Transmission’s tariff. Columbia Gas Transmission’s rate settlement with its customers, which was effective in 2013, established its modernization program and included a reduction in Columbia Gas Transmission’s base rates. Under the modernization settlement, Columbia Gas Transmission and its customers agreed to a mechanism that provides recovery and return on Columbia Gas Transmission’s initial investment of up to $1.5 billion over a five-year period, beginning in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement, Columbia Gas Transmission must annually incur at least $100 million in certain capital expenditures in order to trigger the terms of the modernization settlement’s recovery mechanism. The modernization settlement provides that, absent a FERC-approved agreement reached among Columbia Gas Transmission and its customers to extend the settlement, Columbia Gas Transmission will file a rate case to be effective no later than February 1, 2019. As part of the modernization settlement, Columbia Gas Transmission files an annual revenue sharing report. If, during the settlement, base revenue exceeds $750 million, Columbia Gas Transmission will share 75% of the revenue above $750 million with shippers. The 2014 revenue sharing report reported approximately $639 million of base system revenue.

Growth Projects. We are also pursuing the following significant expansion projects for the Columbia Gas Transmission system, which have either recently been placed in service or will be placed into service over the next several years for a total capital expenditure of approximately $304 million through December 31, 2014, with approximately $2,536 million in additional estimated costs to be paid through the end of 2018:

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Warren County Project. We completed construction of approximately 2.5 miles of new 24-inch pipeline and modifications to existing compressor stations for a total capital cost of approximately $37 million. This project has expanded the system in order to provide up to nearly 250,000 Dth/d of transportation capacity under a long-term, firm contract. The project commenced commercial operations in April 2014.

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West Side Expansion (Columbia Gas Transmission—Smithfield III). This project is designed to provide a market outlet for increasing Marcellus supply originating from the Waynesburg, Pennsylvania and Smithfield, Pennsylvania areas on the Columbia Gas Transmission system. We invested approximately $87 million in new pipeline and compression, which provides up to 444,000 Dth/d of incremental, firm transport capacity and is supported by long-term, firm contracts. The project was placed in service during the fourth quarter of 2014.

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Giles County Project. We invested approximately $25 million for the construction of approximately 12.9 miles of 8-inch pipeline, which will provide 46,000 Dth/d of firm service to a third party located off its Line KA system and into Columbia of Virginia’s system. We have secured a long-term firm contract for the full delivery volume and the project was placed in service in the fourth quarter of 2014.

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Line 1570 Expansion. We replaced approximately 19 miles of existing 20-inch pipeline with a 24-inch pipeline and added compression at an approximate cost of $18 million. The project, which was placed in service during the fourth quarter of 2014, creates nearly 99,000 Dth/d of capacity and is supported by long-term, firm contracts.

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Chesapeake LNG. The project involves the investment of approximately $33 million to replace 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives. This project is expected to be placed in service in the second quarter of 2015.

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East Side Expansion. We have received FERC authorization to construct facilities, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets. Supported by long-term firm contracts, the project will add up to 312,000 Dth/d of capacity and is expected to be placed in service in the fourth quarter of 2015. We plan to invest up to approximately $275 million in this project.

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Kentucky Power Plant Project. We expect to invest approximately $24 million to construct 2.7 miles of 16-inch greenfield pipeline and other facilities to a third-party power plant from Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service, is supported by a long-term firm contract, and will be placed in service in the second quarter of 2016.

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Utica Access Project. We intend to invest approximately $51 million to construct 4.7 miles of 20-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on our system. This project is expected to be in service in the fourth quarter of 2016. We have secured firm contracts for the full delivery volume.

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Leach XPress. We finalized agreements for the installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system, and 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system, and approximately 101,700 horsepower across multiple sites to provide approximately 1.5 MMDth/d of capacity out of the Marcellus and Utica production regions to the Leach compressor station (“Leach CS”) located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. Virtually all of the project’s capacity has been secured with long-term firm contracts. We expect the project to go in service in the fourth quarter of 2017 and will invest approximately $1.4 billion in this project.

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WB XPress. We expect to invest approximately $850 million in this project to expand the WB system through looping and added compression in order to transport approximately 1.3 MMDth/d of Marcellus shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which includes access to the Cove Point LNG terminal. We expect this project to be placed in service in the fourth quarter of 2018.

Transmission system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement with the FERC, we must annually incur at least $100 million in maintenance capital expenditures in order to trigger the terms of the modernization settlement’s recovery mechanism. During 2014, we completed nearly 40 individual projects bringing the total program investment to approximately $618 million. The modernization program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

Competition. Columbia Gas Transmission competes with a number of other interstate pipeline companies in various markets, such as Texas Eastern Transmission Company, Tennessee Gas Pipeline Company, Transcontinental Gas Pipeline Company, Dominion Transmission Inc., Equitrans, and National Fuel Gas Company. Increased competition from alternative options could have a significant financial impact on Columbia Gas Transmission. However, this risk is mitigated through the use of long-term contracts. Continued growing supply as a result of the Marcellus and Utica shale could reduce the demand for storage services.

Columbia Gas Transmission is well positioned to compete, due to its market area location and its flexible low cost services. Additionally, because its system traverses much of the Marcellus and Utica shale areas, Columbia Gas Transmission has seen major producer driven demand and has been able to capitalize on that demand through developing growth projects. This has added diversification to Columbia Gas Transmission’s customer base, which historically has been dominated by large LDCs. Columbia Gas Transmission is able to receive gas from the Gulf, the Appalachian Basin (including Marcellus and Utica shale areas) and from the West. Columbia Gas Transmission also uses its extensive storage network to ensure reliable delivery of supplies.

Columbia Gulf

The Columbia Gulf pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of approximately 3,300 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Historically, the pipeline system provided direct access to Gulf of Mexico and onshore Louisiana supply sources and, through major pipeline interconnects, access to numerous natural gas producing regions, including the South Texas and Louisiana Gulf Coast, North Louisiana, East Texas, North Texas and Appalachian regions. With the rapid development of the Marcellus and Utica shale areas, traditional south-to-north gas flows are beginning to reverse and demand is increasing to transport gas in a southerly direction on Columbia Gulf’s pipelines to access various markets including LNG export facilities and markets in Florida and the Southeast via pipeline interconnects. Columbia Gulf’s pipelines include:

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The Mainline System. Columbia Gulf’s Mainline System consists of three parallel pipelines that extend from southern Louisiana to a pipeline interconnection with Columbia Gas Transmission in northeastern Kentucky. The Mainline System consists of approximately 2,550 miles of pipelines with peak-design throughput capacity of 2.2 MMDth/d; and

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The Louisiana Laterals. The Louisiana Laterals consist of the West Lateral and the East Lateral. The West Lateral extends from an interconnection with the Mainline System along the southern tier of Louisiana westward to Cameron Parish, Louisiana, while the East Lateral extends eastward to New Orleans and Venice, Louisiana. The Louisiana Laterals consist of approximately 700 miles of pipelines with maximum peak-design capacity in excess of 1.0 MMDth/d on each lateral.

The system is connected to approximately 71 natural gas receipt points and approximately 105 natural gas delivery points.

The Columbia Gulf system offers shippers access to two actively traded market hubs—the Columbia Gulf Mainline Pool and the Columbia Gulf Onshore Pool. In addition, Columbia Gulf interconnects with the Henry Hub in South Louisiana and the Columbia Gas Transmission Pool near Leach, Kentucky. Through its

approximately 22 interstate and 10 intrastate pipeline interconnections, Columbia Gulf provides upstream supply to serve growing markets in the mid-Atlantic, Midwest, Florida and southeast. Columbia Gulf also has a project underway that will connect its system with the Cameron LNG export facility.

The development of the Marcellus and Utica shale areas has led to decreased demand to transport gas from the Gulf Coast to northeastern markets and we have been experiencing a corresponding decline in throughput. However, Columbia Gulf has attracted additional throughput by expanding its market and production area access through a strategy of connecting with other pipelines. For example, our new Texas Eastern interconnect in Adair, Kentucky increased our supply access by over 200,000 Dth/d. In addition, Columbia Gulf has recently reconfigured its system so that it can reverse flow on one of its three pipelines and we have secured long-term firm contracts for 100% of the delivery volume on that reversed pipeline. Flows on the other two pipelines will be reversed as part of the projects outlined below.

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Customers. Columbia Gulf transports natural gas for a broad mix of customers, including LDCs, municipal utilities, direct industrial users, electric power generators, marketers and producers and LNG importers and exporters. In general, LDC usage of Columbia Gulf’s pipeline system is declining and producer usage is increasing. Based on firm contracts we have entered into with these producers, we expect that by the end of 2018, a significant portion of our revenues will be generated by producers. In addition to serving markets directly connected to Columbia Gulf’s system, it serves markets and customers in a variety of other regions through numerous interconnections with third-party interstate and intrastate pipelines.

As of December 31, 2014, Columbia Gulf had 74 firm contract customers. Columbia Gulf’s three largest customers for the year ended December 31, 2014 were Washington Gas Light Company, Columbia Gas of Ohio and Antero Resources Corporation. Contracts with these three customers accounted for approximately 10%, 10% and 9% of Columbia Gulf’s contracted revenues, respectively, during 2014, although each of these customers contracted a portion of their reserved capacity to third parties that paid Columbia Gulf directly for the subcontracted amounts. For the twelve months ended December 31, 2014, Columbia Gulf’s top 25 largest non-affiliated customers measured by contracted revenues generated approximately 67% of Columbia Gulf’s transportation.

Contracts. Under transportation agreements governed by its FERC-approved natural gas tariff, Columbia Gulf offers its customers firm and interruptible transportation services. For the twelve months ended

December 31, 2014, approximately 96% of Columbia Gulf’s transportation and storage revenues were derived from firm contracts and approximately 4% were derived from interruptible contracts.

The table below sets forth certain information regarding Columbia Gulf as of December 31, 2014:


	Total Firm Contracted Capacity⁽¹⁾		Weighted Average Remaining Firm Contract Life⁽²⁾
Transportation		3.4 MMDth/d		4.3 years

(1)	Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation capacity regardless of the actual amount of transportation capacity used by the customer during each month.

(2)	Weighted by contracted capacity.

Tariff Rates. Columbia Gulf’s maximum and minimum recourse rates for transportation services are governed by Columbia Gulf’s FERC-approved natural gas tariff. As of December 31, 2014, the rates in effect for 54% of Columbia Gulf’s firm contracts were at the maximum recourse rates prescribed for in our tariff.

In 2011, Columbia Gulf entered into a rate settlement with its customers, which established new base rates under Columbia Gulf’s FERC tariff. The 2011 rate settlement requires Columbia Gulf to file a cost and revenue study by May 1, 2017 but does not require Columbia Gulf to file for new rates. There are no FERC regulations that require Columbia Gulf to file a rate case. Please read “—FERC Regulation.”

Growth Projects.

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West Side Expansion (Columbia Gulf—Bi-Directional). Under the Gulf Bi-Direction Project, we invested approximately $113 million in system modifications and horsepower to provide a firm backhaul transportation path from the Leach, Kentucky interconnect with Columbia Gas Transmission to Gulf Coast markets on the Columbia Gulf system. This investment will increase capacity up to 540,000 Dth/d to transport Marcellus production originating in West Virginia. The project is supported by long-term firm contracts and was placed in service during the fourth quarter of 2014. The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

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Rayne XPress. This project would transport approximately 1 MMDth/d of growing southwest Marcellus and Utica production away from constrained production areas to markets and liquid transaction points. Capable of receiving gas from Columbia Gas Transmission’s Leach XPress project, gas would be transported from the Leach, Kentucky interconnect with Columbia Gas Transmission in a southerly direction towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. The project also includes the creation of a new compressor station. We have secured definitive agreements for firm service for the project’s capacity and expect the project to be placed in service in the fourth quarter of 2017. We expect to invest approximately $383 million on the Rayne XPress project to modify existing facilities and to add new compression.

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Cameron Access Project. We are investing approximately $310 million in an 800,000 Dth/d expansion of the Columbia Gulf system through improvements to existing pipeline and compression facilities, a new state-of-the-art compressor station near Lake Arthur, Louisiana, and the installation of a new 26-mile pipeline in Cameron Parish to provide for a direct connection to the Cameron LNG Terminal. We expect the project to be placed in service in the first quarter of 2018 and have secured long-term firm contracts for approximately 90% of the increased volumes.

Competition. Historically, Columbia Gulf competed primarily with other interstate pipelines for customers seeking upstream transportation service to markets in the northeast, mid-Atlantic, Midwest and southeast.

Columbia Gulf’s primary competitors are Tennessee Gas Pipeline Company, Transcontinental Gas Pipeline Company, Texas Eastern Transmission Company, Texas Gas Pipeline, Natural Gas Pipeline of America, Trunkline Gas Company and ANR Pipeline Company.

With the development of the Marcellus and Utica shale areas, much of Columbia Gulf’s future transportation service will focus on moving gas supply from the Appalachian region into areas where demand is high. Columbia Gulf is in the process of capitalizing on this evolution through several projects to reverse the historic flow on the system, allowing gas to reach the Gulf Coast to serve the market demand of various processing plants and developing LNG export facilities located there. Many historic competitors, such as Transcontinental Gas Pipeline Company, have announced similar initiatives to reverse flow in order to reach the Gulf Coast. Almost all of Columbia Gulf’s southbound capacity is anticipated to be sold before project construction begins. Columbia Gulf is well positioned to compete, as it provides low cost service, including fuel, to the markets it serves. By becoming bi-directional, Columbia Gulf is addressing competitive threats by increasing the flexibility and optionality available to customers on its system. By increasing the number and diversity of supply sources and markets that it interconnects with, the Columbia Gulf pipeline system becomes a more dynamic system that presents greater value to its customers. This not only increases the potential universe of customers that have interest in Columbia Gulf’s transportation services, it also lessens the possibility that future market shifts will affect the value of Columbia Gulf’s pipeline system.

Millennium Pipeline

The Millennium Pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with approximately 43,000 horsepower of installed capacity. Millennium Pipeline has the capability to transport up to 525,400 Dth/d of natural gas to markets across New York’s Southern Tier and lower Hudson Valley, as well as to the New York City markets through its pipeline interconnections. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline and acts as operator for the pipeline in partnership with DTE Millennium Company and National Grid Millennium LLC, which each own an equal remaining share of the company.

The Millennium Pipeline system is connected to 12 natural gas receipt points and 35 natural gas delivery points.

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Customers. Millennium Pipeline transports natural gas for a broad mix of customers, including LDCs, direct industrial users, electric power generators, and marketers and producers. In addition to serving markets directly connected to its system, Millennium Pipeline serves markets and customers through interconnections with third-party interstate pipelines.

As of December 31, 2014, Millennium Pipeline had 17 firm contract customers. Millennium Pipeline’s three largest customers for the year ended December 31, 2014 were Keyspan Gas East Corporation, d/b/a National Grid, Consolidated Edison Company of New York and Southwestern Energy Services Company. Contracts with these three customers accounted for approximately 22%, 20% and 17% of our contracted revenues, respectively, during 2014. For the twelve months ended December 31, 2014, Millennium Pipeline’s top 10 largest non-affiliated customers measured by contracted revenues generated approximately 67% of Millennium Pipeline’s transportation revenue.

Contracts. Under transportation agreements and FERC tariff provisions, Millennium Pipeline offers its customers firm and interruptible transportation services. For the twelve months ended December 31, 2014, approximately 98% of Millennium Pipeline’s transportation and storage revenues were derived from firm contracts and approximately 2% were derived from interruptible contracts.

The table below sets forth certain information regarding Millennium Pipeline as of December 31, 2014:


	Total Firm Contracted Capacity⁽¹⁾		Weighted Average Remaining Firm Contract Life⁽²⁾
Transportation		2.0 MMDth/d		5.7 years

(1)	Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation capacity regardless of the actual amount of transportation capacity used by the customer during each month.

(2)	Weighted by contracted capacity.

Tariff Rates. Millennium Pipeline’s maximum and minimum recourse rates for transportation services are governed by Millennium Pipeline’s FERC-approved natural gas tariff. Terms and conditions for service under this tariff are based on firm capacity reservation charges and both firm and interruptible usage fees for transportation across different zones. As of December 31, 2014, 85% of the rates in effect for Millennium Pipeline’s firm contracts were less than the maximum recourse rates prescribed for in our tariff.

In 2006, the FERC issued an order in a proceeding under Section 7 of the Natural Gas Act accepting the base rates to be charged under Millennium Pipeline’s FERC tariff. In compliance with the order, Millennium Pipeline filed a cost and revenue study in 2011, which was accepted for filing by the FERC in January 2012. Neither the FERC order nor FERC regulations require Millennium Pipeline to file for new base rates, thereby providing rate certainty, subject to further negotiation, the filing of a rate case, or a customer filing a complaint.

Growth Projects.

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Hancock Compressor Project. Millennium Pipeline has invested approximately $40 million to increase firm transportation capacity to its interconnection with a downstream pipeline at Ramapo, New York by 107,500 Dth/d and provide the flexibility to meet an anticipated need for 115,000 Dth/d of firm transportation capacity between an interconnect with the Laser Northeast Gathering System and Columbia Gas Transmission. The project was placed in service in the first quarter of 2014.

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Minisink Compressor Project. Millennium Pipeline has invested approximately $50 million to add compression in Orange County, NY that will effectively increase deliverability at Ramapo to 675,000 Dth/d. This project added two 6,130 horsepower natural gas turbine-driven centrifugal compressors to increase pressure and was placed in service in the second quarter of 2013.

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Competition. Millennium Pipeline was recently constructed to fulfill largely unmet demand and two of its partners are significant customers; as such, Millennium Pipeline has limited direct competition.

Hardy Storage

The Hardy Storage facility is a FERC-regulated interstate natural gas storage system, which consists of 29 storage wells in a depleted gas production field in Hampshire and Hardy counties, West Virginia, 36.7 miles of pipeline and 7,100 horsepower of installed capacity. The facility interconnects with Columbia Gas Transmission and has approximately 12 MMDth of working gas capacity and 176,000 Dth/d of withdrawal capacity. We own a 50% interest in Hardy Storage and act as operator for the system. A third party, Piedmont Natural Gas Company, Inc., owns the remaining 50% interest in Hardy Storage.

Customers. As of December 31, 2014, Hardy Storage had three firm contract customers. These customers were Baltimore Gas and Electric Company, Piedmont Natural Gas Company and Washington Gas Light Company. Contracts with these three customers accounted for approximately 47%, 40% and 13% of contracted revenues, respectively, during 2014.

Contracts. Hardy Storage’s capacity is 100% contracted and its contracts with its customers will expire on March 31, 2023.

Tariff Rates. Hardy Storage’s assets and operations are regulated by the FERC under the Natural Gas Act.

In 2013, Hardy Storage entered into a rate settlement with its customers which established new base rates under Hardy Storage’s FERC tariff. On or before May 1, 2019, Hardy Storage is required to file a cost and revenue study with the FERC. The rate settlement does not require Hardy Storage to file for new base rates, thereby providing rate certainty, subject to further negotiation, the filing of a rate case, or a customer filing a complaint. There are no FERC regulations that require Hardy Storage to file a rate case. Please read “—FERC Regulation.”

Columbia Midstream

Columbia Midstream is a non-FERC regulated business that provides midstream services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 103 miles of gathering pipeline and one compressor station with 6,800 horsepower of installed capacity, as well as a 50% ownership interest in Pennant, which owns wet gas gathering pipeline facilities, a gas processing plant and an NGL pipeline. Columbia Midstream supports the growing production in the Utica and Marcellus shale areas.

Revenues associated with our gathering systems represented 100% of our total revenues for the year ended December 31, 2014. Our gathering system is composed of pipelines ranging in diameter from 16 inches to 24 inches. Columbia Midstream currently gathers natural gas from approximately five receipt points with delivery into three interstate pipelines.

Average throughput on our gathering systems for the year ended December 31, 2014 was 334 MDth/d.

Majorsville Gathering System. The 46-mile Majorsville gathering system is a wet gas gathering pipeline system, located in the Majorsville, West Virginia vicinity and gathers Marcellus shale production for downstream transmission. We have invested approximately $83 million in the system in three projects for the Majorsville gathering system. Substantially contracted with long-term firm service agreements, the pipeline and compression assets allow us to gather and deliver more than 350,000 Dth/d of Marcellus production gas to the Majorsville MarkWest Liberty processing plants operated by MarkWest Liberty Midstream & Resources LLC. Two of the three projects, which were placed into service in August 2010, created an integrated gathering system serving

Marcellus production in southwestern Pennsylvania and northern West Virginia. The projects consisted of the construction of a 22-mile 16-inch low pressure gathering line and a 17-mile 20-inch high pressure gathering line. The third project, which was placed into service in April 2011, involved construction on a 7-mile 16-inch and 20-inch pipeline. The pipelines deliver residue gas from the Majorsville MarkWest Liberty processing plant to the Texas Eastern Wind Ridge compressor station in southwestern Pennsylvania, providing significant additional capacity to Northeastern markets. Long-term firm service agreements are in place with anchor shippers for 100% of capacity. In 2013, the compressor station was updated with four new compressors with a total of 6,800 horsepower.

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Big Pine Gathering System. The Big Pine gathering system consists of 58 miles of pipeline facilities in the hydrocarbon-rich Western Pennsylvania shale production region, including a 45-mile 20-inch pipeline and a 13-mile 24-inch pipeline. We have invested approximately $165 million in the system for right-of-way acquisitions and installation, refurbishment and operation of the pipeline facilities. The newly constructed pipeline system, which was placed in service in April 2013, has an initial combined capacity of 425 MMcf/d. Natural gas production is delivered to Columbia Gas Transmission and two other third-party pipelines in Pennsylvania. There are currently two meters where gas is delivered into Big Pine. Big Pine is currently fully contracted.

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Customers. Our gathering systems have approximately five receipt points with a number of natural gas producers, including Range Resources, Chesapeake Energy and XTO Energy Inc. The largest producer of natural gas delivered to the gathering systems is XTO Energy Inc., which represented 31.3% of the 334 MDth/d of natural gas supplied to our gathering systems for the year ended December 31, 2014.

Contracts. Our gathering systems are primarily supported by long-term, fee-based gas gathering agreements, with terms ranging from 10 to 15 years typically with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. The rates for gathering services are primarily based on the expected capital expenditures and available capacity.

Growth Projects.

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Washington County Gathering. A large producer has contracted with us to build a 21-mile dry gas gathering system consisting of 8-inch, 12-inch, and 16-inch pipelines, a 20-inch lateral, as well as compression, measurement and dehydration facilities. We expect to invest approximately $120 million beginning in 2014 through 2018 and expect to commence construction in the second quarter of 2015. The initial wells are expected to come on-line in the third quarter of 2015. The project is supported with minimum volume commitments and further enhances Columbia Midstream’s relationship with a producer that has a large Marcellus acreage position.

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long-term fee-based agreement with a regional producer, with the remaining capacity expected to be sold to other area producers in the near term. We expect the project to be placed in service in the third quarter of 2015.

Competition. Competition for natural gas gathering is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location of gathering systems, reputation and fuel efficiencies. Our principal competitors for low and high pressure gathering systems include numerous independent gas gatherers and integrated energy companies, who have plans to build gathering facilities to move volumes to interstate pipelines. Some of our competitors have capital resources and control supplies of natural gas greater than we do.

Pennant Joint Venture

We own a 50% ownership interest in Pennant, a joint venture with an affiliate of Hilcorp, which owns approximately 80 miles of wet gas gathering pipeline infrastructure, a gas processing facility and a NGL pipeline. The system is referred to as the Hickory Bend gathering system.

Pennant constructed the system, which includes 20-24 inch wet gas gathering pipeline facilities with a capacity of approximately 500 MMcf/d, a gas processing facility in New Middletown, Ohio that has an initial capacity of 200 MMcf/d and an NGL pipeline with an initial capacity of 45,000 Bbl/d that can be expanded to 90,000 Bbl/d. Consistent with the terms of the joint venture, Columbia Midstream operates the gas processing facility, NGL pipeline and associated wet gas gathering system. The joint venture is designed and anticipated to serve other producers with significant acreage development in the area with an interest in obtaining capacity on the system. The construction of the facilities allows Pennant to become a full-service midstream solution for producers in the northern Utica shale area, offering access to wet gas gathering and processing as well as residue gas and NGL takeaway to attractive market destinations. Our investment in this venture, including the gathering pipeline, related laterals, NGL pipeline and the processing plant, is approximately $197 million. A portion of the facilities were placed in service in the fourth quarter of 2013 and in the second and third quarter of 2014, and the remainder were placed in service in the fourth quarter of 2014.

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Customers. The Pennant gathering system will have four initial receipt points for Hilcorp production. There are several other producers in the Pennant footprint that have significant acreage positions that can be effectively served by the Pennant gathering and processing facilities.

Contracts. The primary term of the anchor gathering and processing agreements, which started in July 2014, is 10 years with multi-year roll over provisions. Once ramp up volumes are achieved, minimum volume commitments will account for approximately 37% and 68% of the initial Pennant gathering and processing capacity, respectively. The rates for gathering and processing service are based on expected capital expenditures and a required rate of return.

Growth Projects. Pennant expects to add additional plant capacity in the next two to five years to support the growing drilling activity in the area. Pennant also intends to construct measurement stations and make connections to the main gathering line to deliver the field gas that will be drilled.

Competition. Competition for natural gas gathering is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location of gathering systems and processing plants, reputation and fuel efficiencies. Competitive factors affecting our processing service also includes availability of capacity, proximity to supply and industry marketing centers and cost efficiency and reliability of service. Our principal competitors for low and high pressure gathering systems and gas processing include numerous independent gas gatherers and integrated energy companies, who have plans to build gathering facilities or gas processing plants. Some of our competitors have capital resources and control supplies of natural gas greater than we do.

We believe that our customer focus, demonstrated by our ability to offer a broad range of services, strategic location of our systems, and our flexibility in considering various types of contractual arrangements, allows us to compete effectively. In our Utica footprint, our early entrance through our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of these resource plays. The strategic location of our assets and the long-term nature of our contracts also provide a significant competitive advantage.

Columbia Energy Ventures, LLC

We own 100% of the ownership interests in CEVCO, a non-FERC regulated business that manages our mineral rights positions in the Marcellus and Utica shale areas including the production rights to approximately 460,000 acres. CEVCO has subleased the production rights in four storage fields in Ohio, West Virginia and Pennsylvania, and also has contributed its production rights in another storage field.

Customers. CEVCO has subleased the production rights below the four storage fields to five producers, with production taking place on three of those fields. CEVCO has also contributed its production rights to another storage field to Hilcorp, and participates as a working interest partner in the development of a broader acreage dedication. CEVCO has pursued, and will continue to pursue, opportunities to leverage its mineral rights positions into broader gathering and processing projects for Columbia Midstream.

Contracts. Each sublease is negotiated separately and terms vary depending on each unique storage field and the expectations of the sublessee. CEVCO receives an overriding royalty from the producers for successful drilling efforts on the subleased acres. Some of the sublease agreements also allow CEVCO the option to participate in the subleased acres as a working interest owner. CEVCO is currently participating as a working interest owner in one of its subleases. The agreement with Hilcorp gives CEVCO the option to participate in a specified acreage area in the Utica/Point Pleasant formation, with CEVCO having both a working interest and overriding royalty interest in the well production.

Growth Projects. We have invested approximately $28 million in the Cardinal Upstream project, in which we are a 5% working interest owner with Hilcorp in the development of wells. In addition, we have received an overriding royalty interest of 0.7% on all drilling activity in the area of mutual interest. Currently, approximately 29 wells are producing with approximately 50 wells scheduled to be drilled and completed in the next 18 months. Beginning in 2015, we expect to make an annual contribution of approximately $22 million to the project.

Crossroads Pipeline Company

Crossroads is a 202-mile interstate natural gas pipeline operating in Indiana and Ohio. Crossroads has multiple interconnects including: Natural Gas Pipeline Company of America, Trunkline Gas Company, Vector Pipeline and Panhandle Eastern that allow it to access mid-continent, Rocky Mountain, Gulf Coast, Permian and Canadian supplies. Crossroads accesses markets in Indiana, Illinois, Michigan and Ohio.

CNS Microwave

CNS Microwave is an exempt telecommunications company and an indirect subsidiary of CPG. With assets in Pennsylvania, Maryland, Virginia, West Virginia, Ohio, Kentucky, Tennessee, Mississippi and Louisiana, CNS Microwave provides ancillary communication services to us and third parties.

FERC Regulation

General. Our interstate natural gas transportation and storage system operations are regulated by the FERC under the Natural Gas Act and the NGPA, and the FERC’s regulations under those statutes. Generally, the FERC’s authority extends to:

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interstate transportation and storage of natural gas;

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rates, charges, and operating terms and conditions for natural gas transportation and storage services;

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the types of services we may offer our customers;

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certification and construction of new facilities;

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initiation, acquisition, extension or abandonment of services or facilities;

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maintenance of accounts and records;

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affiliate interactions;

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depreciation and amortization policies; and

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the initiation and discontinuation of services.

Our interstate pipeline companies hold certificates of public convenience and necessity issued by the FERC pursuant to Section 7 of the Natural Gas Act permitting the construction, ownership, and operation of their respective interstate natural gas pipeline and storage facilities and the provision of related activities and services. These certificate authorizations require our interstate pipeline companies to provide on a non-discriminatory basis open-access services to all customers who qualify under their respective FERC-approved tariff.

The FERC regulates the rates and charges for transportation and storage in interstate commerce. Interstate pipeline companies may only charge rates that they have been authorized to charge by the FERC. In addition, interstate pipeline companies may only charge rates that have been found to be just and reasonable. The Natural Gas Act prohibits interstate pipeline companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum and minimum recourse rates that may be charged by our interstate pipeline companies for transportation and storage services are established through the FERC’s ratemaking process. The maximum filed recourse rates for these services are based on the cost of service including recovery of and a return on the company’s actual prudent historical cost investment. In addition, the FERC’s policy permits our interstate pipeline companies to include an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if we prove that the ultimate owners of our partnership interests have an actual or potential income tax liability on such income. The maximum applicable recourse rates and terms and conditions for service are set forth in each natural gas company’s FERC-approved tariff.

Pursuant to the FERC’s jurisdiction over rates, proposed rate increases may be challenged by protest and existing rates may be challenged by complaint or sua sponte by the FERC. Any successful challenge to our existing or proposed rates, or changes in FERC’s ratemaking policies, could have an adverse impact on our revenues associated with providing transportation and storage services. The most recent rate cases establishing the maximum recourse rates that each of our interstate pipeline companies is allowed to charge are described above in “—Our Operations and Operating Assets.”

Most interstate pipeline companies are authorized to offer discounts from their FERC-approved maximum recourse rates when competition warrants such discounts. Interstate pipeline companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer the recourse rate to a prospective shipper as an alternative to the negotiated rate. Interstate pipeline companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory.

Energy Policy Act of 2005. The EPAct 2005 amended the Natural Gas Act, to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and provided the FERC with additional civil penalty authority. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of EPAct 2005. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amended the Natural Gas Act and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, FERC rules, regulations and orders, or the terms of our tariffs on file with the FERC, up to $1,000,000 per day per violation.

Failure to comply with the Natural Gas Act, the NGPA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and/or criminal remedies.

Proposed Rulemaking on Gas-Electric Coordination. On March 20, 2014, the FERC issued a notice proposing revisions to its natural gas regulations that it states are designed to better coordinate the scheduling for natural gas and electricity markets. The FERC states that the revisions are intended to address impacts on reliable and efficient operation of both industries that have resulted from the increased reliance on natural gas by electric generation, and to provide increased flexibility for natural gas customers. The proposed rules would change the start of the natural gas operating day and increase the number of intraday nomination cycles to four. The scheduling changes would impose additional systems and administrative costs on our interstate pipeline companies.

Regulation of Gathering Pipelines. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC under the Natural Gas Act. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Complaint-based regulation generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Seasonality

Natural gas demand for heating is impacted by weather, which in turn influences the value of transportation and storage. Peak demand for natural gas typically occurs during the winter months, however, because a high percentage of our revenues are derived from firm capacity reservation fees under long-term contracts, our transportation and storage revenues are not generally seasonal in nature. Net revenues for 2014 were approximately 26% in the first quarter, 25% in the second quarter, 24% in the third quarter, and 25% in the fourth quarter.

Environmental and Occupational Health and Safety Regulation

General. Our activities are subject to stringent and complex federal, state, and local laws and regulations governing worker safety and health as well as environmental protection, including air emissions, water quality, wastewater discharges, solid waste management, and natural resource, ecosystem and species protection and management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, plans, and other approvals. These laws and regulations also can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of our wastes; requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators; limiting or prohibiting construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; imposing specific health and safety criteria addressing worker protection; and preventing continued operation of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations.

We accrue for expenses associated with environmental liabilities when the costs are probable and reasonably estimable. The amount of any accrual for environmental liabilities could change substantially in the future due to factors including the nature and extent of any contamination that we may be required to remediate, changes in remedial, material handling, or permitting requirements, technological changes, discovery of new information, and the involvement and direction taken by the EPA, FERC, DOT and any other governmental authorities on these matters.

We believe that compliance with existing federal, state and local environmental laws and regulations are not likely to have a material adverse effect on our business, financial condition, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental and worker health and safety laws and regulations, as amended from time to time, that are applicable to our natural gas transportation activities.

Waste Management. Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), Toxic Substance Control Act, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous wastes, which, pursuant to a regulatory exemption, currently includes certain wastes associated with the exploration and production of oil and natural gas.

Site Remediation. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for the disposal of hazardous substances at offsite locations, such as landfills. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. If we are considered a responsible party under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or wastes into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own or lease properties that for many years have been used for the transportation and compression of natural gas. Although we typically have used operating and disposal practices that were standard in the industry at the time, wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

Columbia Gas Transmission continues to conduct work at specific sites subject to a 1995 AOC with the EPA. The AOC requires Columbia Gas Transmission to investigate and remediate historic waste management areas. The cost of future remediation has been estimated based upon the information available, applicable remediation standards and experience at similar facilities. The actual future expenditures depend on many factors, including the nature and extent of contamination and the method of cleanup.

Air Emissions. The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

We may incur significant expenditures in the future for air pollution control equipment in connection with revised or changing regulatory requirements and in obtaining or maintaining operating permits and approvals for air emissions. For instance, in 2012, the EPA published final rules that subject oil and natural gas transmission and storage operations, among others, to regulation under the New Source Performance Standards and National Emission Standards of Hazardous Air Pollutants federal programs and impose, among other things, more stringent standards for monitoring and repairing volatile organic compound emissions from equipment leaks as well as added monitoring requirements of other equipment and processes. In addition, we may be required to supplement or modify our air emission control equipment and strategies due to changes in EPA’s national ambient air quality standards for ozone and fine particulates, changes in state implementation plans for controlling air emissions in areas that have not achieved EPA’s air quality standards, or stricter regulatory requirements for sources of hazardous air pollutants. In addition, in April 2014, the Pennsylvania Department of Environmental Protection proposed a rule, “Additional RACT Requirements for Major Sources of NOx and VOCs,” which may require emissions reductions from several of Columbia Gas Transmission’s turbines and reciprocating engines. The rule is expected to be finalized by the end of 2015. We are required to monitor our facilities for emissions and leaks of certain gases commonly referred to as GHGs, including carbon dioxide and methane, and new requirements for addressing GHGs from our pipelines may apply in the future. Compliance with existing air emissions requirements may cause us to incur potentially significant costs with respect to our operations. However, we do not believe that compliance with any such future requirements will have a material adverse effect on our operations.

Scientific studies have suggested that emissions of GHGs may be contributing to warming of the Earth’s atmosphere. In December 2009, the EPA made findings that emissions of GHGs present an endangerment to public health and the environment and subsequently has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews regarding GHGs for certain large stationary sources that are already potential major sources of conventional pollutant emissions, regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities in the U.S. on an annual basis. On March 28, 2014, President Obama announced his methane emissions initiative that will focus on methane emissions reduction from specified sources including, among others, the oil and natural gas business sector. While we participate in the Natural Gas Star program, a voluntary program to identify leaks from natural gas pipelines and emissions from compressor stations and other combustion sources along the pipeline, and identify and encourage reduction of those leaks and emissions, the EPA may propose emission standards or performance standards at some future time to further address GHGs from pipelines. Additionally, while the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, in the absence of any significant activity by Congress in recent years to adopt such legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Also, there exists the possibility that states and the U.S. Congress may in the future legislate to reduce emissions of GHGs, which legislation may include a carbon tax on GHG

emissions. Natural gas has a lower GHG emission rate than other fossil fuels when combusted. However, it has a high GHG emission rate when released without combustion. Therefore, regulatory or legislative actions can have a mixed impact on natural gas. We are monitoring and reporting GHG emissions from our operations pursuant to the EPA’s GHG emissions reporting rule and further believe that our programs mitigate the risk from GHG regulation by minimizing leaks of uncombusted natural gas. The adoption of any legislation or regulations that imposes a carbon tax, requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for our transportation services. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our operations.

Water Discharges. The federal Water Pollution Control Act (“CWA”) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. and covered state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Spill prevention, control and countermeasure requirements under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a tank spill or leak. The CWA also regulates storm water runoff from certain industrial and construction facilities. Accordingly, some projects of the company may be required to obtain and maintain storm water discharge permits, comply with mitigation measures, and monitor and sample storm water runoff from their facilities. Additionally, certain construction activities that impact streams or wetlands are required to obtain and follow disturbance and fill permits. Under the CWA, federal and state regulatory agencies may impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. In the event that any releases from our pipelines were to threaten drinking water systems, we would have to take actions to mitigate any damage to drinking water supplies.

The federal Oil Pollution Act of 1990 (“OPA”), which amends and augments the CWA, establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills, mitigation of spills, and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to an oil spill.

Environmental Impact Assessments and Plans. Significant federal decisions, such as issuance of a Certificate of Public Convenience and Necessity or permit authorizing construction of a new interstate gas transmission pipeline or authorizing natural gas transportation activities to be conducted on federal lands, are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the FERC, to evaluate major agency actions having the potential to impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment or an Environmental Impact Statement, depending upon the potential impacts, that assess the potential direct, indirect and cumulative impacts of a proposed project. Environmental Assessments and Environmental Impact Statements are made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA, which process has the potential to delay, limit the scope of, or increase the cost of, any construction projects that we may pursue.

Endangered Species Act Considerations. Our pipeline maintenance or construction activities may adversely affect wildlife, migratory birds, or a natural ecosystem that supports a protected animal or plant. We are required by various laws, including the federal Endangered Species Act (“ESA”) and comparable state laws to identify potential impact through species surveys and to take actions to mitigate possible impacts. In some cases, we may be required to submit plans for approval to protect such species. While some of our facilities may be located in

areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. We have developed a Habitat Conservation Plan and received an Incidental Take Permit from the United States Fish and Wildlife Service for a one-mile corridor around our current footprint, excluding midstream assets. This will satisfy most of the current requirements of the ESA and provides protection in the event of take of an endangered species.

In areas where we plan to conduct expansion activities, the ESA could cause us to incur increased costs arising from species protection measures and could result in delays or limitations in the scope of development of such projects. However, we do not believe that compliance with any ESA requirements will have a material adverse effect on our operations.

Employee Health and Safety. We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Some of our facilities are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security (“DHS”), to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS adopted Risk Based Facility Tiering and some of our facilities are subject to enhanced security requirements.

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions, but the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it may seek to further expand its regulation of hydraulic fracturing. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. While we do not conduct horizontal hydraulic fracturing, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our natural gas exploration and production customers’ operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could adversely affect our natural gas transmission and storage services as well as our midstream business expansion opportunities. Further, several federal governmental agencies have conducted or are conducting reviews and studies on the environmental aspects of hydraulic fracturing activities, including the White House Council on Environmental Quality, the EPA, the federal Bureau of Land Management, and the U.S. Department of Energy. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

Pipeline Safety and Maintenance

Our natural gas pipeline operations are subject to regulation by the PHMSA of the DOT under the NGPSA. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities. Pursuant to the authority granted under the NGPSA, PHMSA has promulgated regulations governing pipeline design, installation, testing, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures.

The NGPSA has been amended from time to time, including by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The PSI Act established mandatory inspections for all U.S. natural gas transportation pipelines, and some gathering lines in high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas. The PIPES Act required mandatory inspections for certain natural gas transmission pipelines in HCAs and required that rulemaking be issued for, among other things, pipeline control room management. Pursuant to the authority granted under the NGPSA, as amended, PHMSA has established a series of rules requiring pipeline operators such as us to develop and implement integrity management programs for natural gas transmission pipelines in HCAs that require the performance of frequent inspections and other precautionary measures. PHMSA may assess penalties for violations of these and other requirements imposed by its regulations. We have met the regulatory deadline to perform a baseline assessment of all originally identified HCAs by December 17, 2012. In addition, since 2007, we have performed initial assessments on over 3,690 miles of pipeline mainly using in-line inspection methods. This includes approximately 300 miles of high consequence areas. In addition, beginning in 2010, we began reassessment on many pipeline segments initially inspected under the program. Total costs of the program between 2009 and 2013 were approximately $181 million ($96 million in capital costs and $85 million in expenses). Regulations require that new high consequence areas be identified annually. New HCAs identified are required to be assessed within ten years. We currently estimate an annual average cost of approximately $50 million for years 2014 through 2016 to perform necessary integrity management program testing on our pipelines required by existing PHMSA regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, for which costs could be substantial. However, we do not expect that any such costs would be material to our financial condition or results of operations.

Most recently, the NGPSA was amended on January 3, 2012, when President Obama signed the 2011 Pipeline Safety Act, which reauthorized funding for federal pipeline safety programs through 2015 and required increased safety measures for natural gas transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines that operate above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. In addition, PHMSA has recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have reviewed all of our maximum allowable operating pressure (“MAOP”) records in populated areas in compliance with the advisory bulletin. In addition, we are in the process of completing MAOP records validation on the rest of our pipeline system. We continue to research areas where records could not be found and/or areas where records may not support the current MAOP of the pipeline.

We believe that our natural gas pipeline operations are in substantial compliance with currently applicable PHMSA requirements. Nonetheless, the safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any future implementation of PHMSA rules or any future issuance or reinterpretation of PHMSA guidance with respect to safety involving natural gas pipelines could require us to

install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our operational results or financial condition. For example, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency was seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. In addition, PHMSA is currently in the process of drafting regulations on an integrity verification process for certain pipeline installed before the pipeline safety regulations were enacted as well as for other pipe with legacy issues. Under this process certain pipelines may require testing, retesting, or replacement to meet the standards. These rules are still in the process of being drafted and PHMSA continues to evaluate the public comments received with respect to more stringent integrity management. We continue to monitor regulatory developments associated with the pending regulations to help anticipate future operational and financial risks associated with such requirements.

While states are largely preempted by federal law from regulating pipeline safety, states may assume responsibility for enforcement of federal intrastate pipeline safety regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with state laws and regulations applicable to our operations. We inspect our pipelines regularly in compliance with federal and state maintenance requirements and have implemented inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements. For example, we maintain a corrosion control program to protect the integrity of the pipeline and prolong its life. The corrosion control program includes the installation and operation of groundbeds and rectifiers along the pipeline system to maintain adequate cathodic protection, as required by PHMSA. We determine the adequacy of this program through bi-monthly monitoring of the output of these systems, annual checks of cathodic protection readings at various points along the pipeline and at compressor stations as well as by performing close interval potential surveys. We also monitor the pipeline internally both by sampling liquids or solids that we remove from the pipeline and by performing an internal inspection whenever the interior of the pipeline is exposed. We inspect the external coating condition of the pipeline every time we excavate and expose the pipeline. In addition, many of our pipelines are inspected through the use of in-line inspection tools. Such tools can detect metal loss and other anomalies on the pipeline. Significant anomalies are investigated and repaired. The application of these monitoring and inspection techniques assist us in controlling and reducing metal loss and limiting corrosion, which we believe will extend the service life of the pipeline.

On December 11, 2012, a natural gas pipeline incident involving an ignition and fire occurred in northern Kanawha County, West Virginia, along a 20-inch diameter Columbia Gas Transmission Line SM-80. The incident resulted in damage to several residences. However, there were no fatalities or serious injuries. On December 20, 2012, PHMSA issued a compliance order for the incident. We fulfilled all of the requirements of the order, and on April 2, 2014, PHMSA issued a letter closing the order and stating that no further action was contemplated. An investigation of the incident was performed by the National Transportation Safety Board (“NTSB”). NTSB issued a final accident report concerning the incident on March 10, 2014. The report contained three process recommendations to Columbia Gas Transmission and one recommendation to PHMSA. Columbia Gas Transmission is in the process of implementing measures to comply with those recommendations. There are two remaining civil actions related to the incident. Both are primarily property damage claims that are in the early stages of discovery.

A pipeline rupture and fire occurred on February 13, 2014 on a 30-inch diameter Columbia Gulf pipeline, Line 200, in Adair County, Kentucky. The incident resulted in the loss of several houses and associated damages, however, there were no fatalities or serious injuries. PHMSA issued a Corrective Action Order (“CAO”) for the incident on February 14, 2014. The order required, among other things, the reduction of operating pressure along a 250 mile segment of the pipeline and other actions to assess the cause of the event and determine if similar conditions exist elsewhere on the pipeline. In April 2014, Columbia Gulf issued its final root cause analysis

report and thereafter continued to comply with all elements of the CAO. On March 5, 2015, PHMSA issued a letter to Columbia Gulf finding that Columbia Gulf had complied with all requirements in the CAO and advising the matter was now closed. Only one property damage claim from this matter remains to be resolved.

A pipeline rupture occurred on Columbia Gulf Line 100 on December 14, 2007. The incident resulted in one fatality. We performed a comprehensive assessment and corrective measures on our mainline pipelines in the Columbia Gulf pipeline system following the event. There are no known outstanding regulatory issues associated with this event.

Title to Properties

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to easements or surface leases between us, as lessee, and the fee owner of the lands, as lessors. We, our predecessor or our respective affiliates, have leased these lands, in some cases, for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, permit or license held by us or to our title to any material lease, easement, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, permits and licenses.

Insurance

Our insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.

Facilities

Please refer to our disclosure above for a description of the location and general character of our principal physical properties, in particular under the subheadings “—Our Operations and Operating Assets” and “—Title to Properties.” Our headquarters are located in Houston, Texas and are leased under a lease agreement which expires on June 30, 2021.

Employees

As of December 31, 2014, we had approximately 1,483 employees. Approximately 17% of these employees are covered by collective bargaining agreements, none of which will expire within one year of the Separation. We believe that our relationship with our employees is generally good.

Legal Proceedings

In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including, environmental claims and employee related matters. See “—Environmental and Occupational Health and Safety Regulation” above. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.

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MANAGEMENT

Executive Officers Following the Separation

The following table sets forth certain information as of June 2, 2015 regarding the individuals who are expected to serve as our executive officers following the Separation, including their anticipated titles following the Separation. All of the individuals are currently employees of NiSource or one of its subsidiaries. After the Separation, none of these individuals will be employed by NiSource.


Name	Age	Position
Robert C. Skaggs, Jr.	61	Chief Executive Officer
Stephen P. Smith	54	Executive Vice President and Chief Financial Officer
Glen L. Kettering	60	President
Stanley G. Chapman, III	49	Executive Vice President and Chief Commercial Officer
Shawn L. Patterson	42	Executive Vice President and Chief Operations Officer
Brett A. Stovern	49	Executive Vice President and Chief Operating Officer for Columbia Midstream
Karl Brack	50	Senior Vice President of Human Resources and Employee Engagement
Robert E. Smith	46	General Counsel, Senior Vice President and Corporate Secretary
Jon D. Veurink	51	Senior Vice President and Chief Accounting Officer

Robert C. Skaggs, Jr.

Mr. Skaggs serves as President and Chief Executive Officer of NiSource, positions he has held since October 2004 and July 2005, respectively. He also is a past chairman and current director of the American Gas Association’s board of directors and has served on the board of directors of the Southeastern Gas Association. He is a member of the Midwest Energy Association, the American Bar Association, the Energy Bar Association and the West Virginia Bar Association. He also is a trustee of the NiSource Charitable Foundation and has served in leadership roles for a variety of charitable, community and civic efforts. Mr. Skaggs earned a Bachelor of Arts degree in Economics from Davidson College, a Juris Doctor degree from West Virginia University College of Law and a Master of Business Administration degree from Tulane University. Mr. Skaggs’ extensive energy industry background, leadership experience developed while serving in several executive positions and strategic planning and oversight brings important experience and skill to our board of directors. Mr. Skaggs is expected to serve as our Chairman of the Board and Chief Executive Officer effective at the time of the Separation.

Stephen P. Smith

Mr. Smith has been the Executive Vice President and Chief Financial Officer of NiSource since 2008. Mr. Smith earned a Master of Business Administration degree from the University of Chicago Graduate School of Business and a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Mr. Smith is expected to serve as our Executive Vice President and Chief Financial Officer effective at the time of the Separation.

Glen L. Kettering

Mr. Kettering serves as Executive Vice President and Group Chief Executive Officer for NiSource’s Columbia Pipeline Group business unit, positions he has held since April 2014. Prior to April 2014, Mr. Kettering served as Senior Vice President, Corporate Affairs, where he was responsible for leading NiSource’s investor relations, communications and federal government affairs functions. He joined the law

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department of Columbia Gas Transmission in 1979 and has served in a variety of legal, regulatory, commercial and executive roles, including President of Columbia Gas Transmission and Columbia Gulf. Mr. Kettering earned a Bachelor of Arts degree in Business Administration from West Virginia University and a Juris Doctor degree from the West Virginia University College of Law. Mr. Kettering is expected to serve as our President effective at the time of the Separation.

Stanley G. Chapman, III

Mr. Chapman serves as Executive Vice President and Chief Commercial Officer for various CEG subsidiaries, a position he has held since January 2014. Prior to this position, he served as Senior Vice President of Marketing & Customer Services, a position he held since joining NiSource in December 2011. Prior to joining NiSource, Mr. Chapman was employed by El Paso Pipeline Company and its predecessor Tenneco Energy for nearly 23 years, where he last served as Vice President for Marketing, Business Development and Asset Optimization for its eastern pipelines. He currently is a member of the Interstate Natural Gas Association of America, the Southern Gas Association and the North American Energy Standards Board where he holds various leadership and committee positions. Mr. Chapman earned a Bachelor of Science degree in Economics from Texas A&M University along with a Master of Business Administration from the University of St. Thomas. Mr. Chapman is expected to serve as our Executive Vice President and Chief Commercial Officer effective at the time of the Separation.

Shawn L. Patterson

Mr. Patterson serves as President of Operations and Project Delivery of NiSource’s Columbia Pipeline Group business unit, a position he has held since March 2012. Mr. Patterson has held various operational leadership roles with NiSource Electric and Gas utilities for the past 20 years. Prior to his career at Columbia Pipeline Group, Mr. Patterson served as the Chief Operating Officer for NiSource Gas Distribution. He currently serves on the board of the Southern Gas Association and is a member of the Governor’s STEM Council in West Virginia. Mr. Patterson earned a Bachelor of Science degree in Civil Engineering from Rose Hulman Institute of Technology along with a Master of Business Administration from the University of Notre Dame. Mr. Patterson is expected to serve as our Executive Vice President and Chief Operations Officer effective at the time of the Separation.

Brett A. Stovern

Mr. Stovern serves as Chief Operating Officer of Midstream Services in NiSource’s Columbia Pipeline Group business unit, a position he has held since April 2014. Mr. Stovern was Columbia Pipeline Group’s Chief Financial Officer from 2010 to April 2014. Prior to his career at Columbia Pipeline Group, Mr. Stovern was Vice President and Treasurer of AGL Resources Inc. Mr. Stovern earned a Bachelor of Science degree in Accounting from California State Polytechnic University and is a Certified Public Accountant. Mr. Stovern is expected to serve as our Executive Vice President and Chief Operating Officer for Columbia Midstream effective at the time of the Separation.

Karl Brack

Mr. Brack has served as the Senior Vice President of Corporate Affairs of NiSource since April 2014. In this role, Mr. Brack oversees corporate external and internal communications, federal government affairs and corporate philanthropy. Mr. Brack joined Columbia Gas Transmission in 1987 and has served in a variety of business unit and corporate communications, organizational development and employee engagement roles, including as NiSource’s Vice President of Communication and Engagement Strategies from 2006 until his appointment to his current position. Mr. Brack earned a Bachelor of Arts degree in Journalism/Public relations from Marshall University and a Master of Science in Industrial Relations from University of West Virginia Graduate College. He is a member and past president of the Public Relations Society of America’s West Virginia chapter. Mr. Brack is expected to serve as our Senior Vice President of Human Resources and Employee Engagement effective at the time of the Separation.

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Robert E. Smith

Mr. Smith has served as Corporate Secretary of NiSource since April 2013 and as Vice President and Deputy General Counsel of NiSource since September 2008. Mr. Smith serves as chair of the board of directors of Global Action and was on the national board of the Society of Corporate Secretaries and Governance Professionals, where he was both chair of its Policy Advisory Committee and a member of its Executive Steering Committee. Mr. Smith earned a Bachelor of Arts degree from the University of South Alabama and a Juris Doctor degree from The Ohio State University. Mr. Smith is expected to serve as our Senior Vice President and General Counsel effective at the time of the Separation.

Jon D. Veurink

Mr. Veurink serves as Chief Financial Officer of NiSource’s gas distribution business unit, a position he has held since April 2014. Mr. Veurink was the NiSource Chief Accounting Officer from 2010 to April 2014. Mr. Veurink earned a Bachelor of Arts degree in Business Administration/Accounting from Alma College, and is a Certified Public Accountant. Mr. Veurink is expected to serve as our Senior Vice President and Chief Accounting Officer effective at the time of the Separation.

Our Board of Directors Following the Separation and Director Independence

The following table sets forth information as of June 2, 2015 with respect to those persons who are expected to serve on our board of directors following the Separation.


Name	Age		Position
Robert C. Skaggs, Jr.		61	Chairman of the Board
Sigmund L. Cornelius		60	Director
Marty R. Kittrell		58	Director
W. Lee Nutter		71	Director
Deborah S. Parker		62	Director
Lester P. Silverman		68	Director
Teresa A. Taylor		51	Director

We currently expect that, immediately following the Separation, our board of directors will consist of seven members. We anticipate that our board of directors will be comprised of a majority of independent directors and that committees of our board of directors will be comprised solely of independent directors, to the extent required by the NYSE listing standards.

Sigmund L. Cornelius

Mr. Cornelius has been a NiSource director since 2011. Since April 2014, Mr. Cornelius has been President and Chief Operating Officer of Freeport LNG, LLC, an LNG terminal business. From October 2008 to January 2011, Mr. Cornelius served as Senior Vice President, Finance and Chief Financial Officer of ConocoPhillips, an integrated energy company. During his 30-year tenure at ConocoPhillips, Mr. Cornelius served in various positions, including Senior Vice President, Planning, Strategy and Corporate Affairs from September 2007 to October 2008; Regional President, Exploration & Production-Lower 48 from 2006 to September 2007; and President, Global Gas from 2004 to 2006. Mr. Cornelius served on the board of DCP Midstream L.P. from 2007 to 2008 and is also a director of USEC, Inc., Carbo Ceramics Inc., Western Refining, Inc. and Parallel Energy Inc.

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Mr. Cornelius has significant experience in the oil and natural gas industry, which enables him to provide valuable insight on issues impacting our business. He also has significant experience in exploration, production and the midstream business, which is valuable to us as we expand our presence in the Utica and Marcellus shale gas regions. In addition, as the former Chief Financial Officer of a public company, he has extensive experience and skills in the areas of corporate finance, accounting, strategic planning and risk oversight.

Marty R. Kittrell

Mr. Kittrell has been a NiSource director since 2007. In February 2011, Mr. Kittrell retired as Executive Vice President & Chief Financial Officer of Dresser, Inc. (“Dresser”), after serving in that capacity since December 2007. Dresser, a worldwide leader in providing highly engineered products for the global energy industry, was acquired by General Electric in February 2011. Prior to joining Dresser, Mr. Kittrell was Executive Vice President and Chief Financial Officer of Andrew Corporation from October 2003 to December 2007. Mr. Kittrell is also a director of On Assignment, Inc.

Mr. Kittrell brings to the board of directors over 25 years of experience as a Chief Financial Officer. He has served in the role of Chief Financial Officer at several public companies. As a result of this experience, he has significant expertise with financial reporting issues facing us, including SEC reporting, and Sarbanes-Oxley Act internal control design and implementation. His recent position with a company that supplies infrastructure products to the energy industry gives Mr. Kittrell a particular familiarity with the issues facing our gas transmission and storage and gas distribution businesses. Mr. Kittrell also has extensive experience with mergers and acquisitions and capital markets transactions. He formerly practiced accounting with a national accounting firm and is an active member of the American Institute of CPAs, the National Association of Corporate Directors, and Financial Executives International. Mr. Kittrell also shows a commitment to education through his service on the board of trustees of a university.

W. Lee Nutter

Mr. Nutter has been a NiSource director since 2007. Prior to his retirement in 2007, Mr. Nutter was Chairman, President and Chief Executive Officer of Rayonier, Inc., a leading supplier of high performance specialty cellulose fibers and an owner of timberlands and other higher value land holdings. Mr. Nutter was a director of Rayonier, Inc. from 1996 to 2009. He is also a director of Republic Services Inc. and the non-executive Chairman of J.M. Huber Corporation. He is also a member of the Advisory Board at the University of Washington Foster School of Business.

Mr. Nutter’s former positions as Chairman and Chief Executive Officer of a forest products company, and his current positions as director of one company engaged in waste management and another involved in the forest products and energy industries, give him a particular familiarity with the issues involved in managing natural resources. These issues include compliance with environmental laws and exercising responsible environmental stewardship. Mr. Nutter also has an extensive background and familiarity in human resource and compensation issues. In addition, as a former Chief Executive Officer, Mr. Nutter understands how to address the complex issues facing major corporations.

Deborah S. Parker

Ms. Parker has been a NiSource director since 2007. Ms. Parker retired as Senior Vice President, Quality and Environmental, Health and Safety of Alstom Power, a business segment of Alstom, in August 2014, after serving in that capacity since April 2011. Alstom Power is a global leader in power generation based in Zurich, Switzerland. From April 2008 until April 2011, Ms. Parker was President and Chief Executive Officer of International Business Solutions, Inc. (“IBS”), a provider of strategic planning and consulting services to profit and not-for-profit organizations. Before joining IBS, Ms. Parker was Executive Vice President and Chief Operations Officer of the National Urban League from July 2007 through April 2008. Prior thereto, Ms. Parker

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served in numerous operating positions, including Vice President of Global Quality at Ford Motor Company. During her tenure at Ford, Ms. Parker also served as Chief Executive Officer and Group Managing Director at Ford Motor Company of Southern Africa (Pty) Ltd. from September 2001 to December 2004.

Ms. Parker brings a unique combination of community development and industrial management experience to the board of directors. As a Senior Vice President of quality, environmental, health and safety of a global power generation firm, she brings knowledge and understanding of operations, health and safety issues that are valuable to us as we execute on our commitment to increase our investment in environmental projects and focus on safety. As a former Chief Executive Officer of a consulting firm and Chief Operating Officer of a national civil rights organization dedicated to economic empowerment of historically underserved urban communities, Ms. Parker brings expertise and understanding with respect to the social and economic issues confronting us and the communities we serve. As a result of her 23-year career at a global manufacturing company, Ms. Parker has extensive experience managing industrial operations, including turning around several struggling business units, finding innovative solutions to management and union issues, implementing quality control initiatives and rationalizing manufacturing and inventory. This experience positions her well to provide valuable insights on our operations and processes, as well as on social issues confronting us.

Lester P. Silverman

Mr. Silverman is Director Emeritus of McKinsey & Company, Inc., having retired from the international management consulting firm in 2005. Mr. Silverman joined McKinsey in 1982 and was head of the firm’s Electric Power and Natural Gas practice from 1991 to 1999. From 2000 to 2004, Mr. Silverman was the leader of McKinsey’s Global Nonprofit Practice. Previous positions included Principal Deputy Assistant Secretary for Policy and Evaluation in the U.S. Department of Energy from 1980 to 1981 and Director of Policy Analysis in the U.S. Department of the Interior from 1978 to 1980. He is a trustee of and advisor to several national and Washington, D.C.-area non-profit organizations. Mr. Silverman also is a member of the board of directors of Pepco Holdings, Inc., a position he has held since May 2006.

Mr. Silverman brings several valuable attributes to our board of directors, including his broad experience with the energy industry and extensive experience in government and public policy. Mr. Silverman was a consultant to electric and gas utilities for 23 years and has public policy experience in the energy field.

Teresa A. Taylor

Ms. Taylor has been a NiSource director since 2012. Ms. Taylor is currently Chief Executive Officer of Blue Valley Advisors, LLC. Ms. Taylor served as Chief Operating Officer of Qwest Communications, Inc. (“Qwest”), from August 2009 to April 2011. Prior thereto, she was Qwest’s Executive Vice President, Business Markets Group from January 2008 to April 2009 and served as Qwest’s Executive Vice President and Chief Administrative Officer from December 2005 to January 2008. Ms. Taylor served in various positions with Qwest and the former US West since 1987. Ms. Taylor also is a director of T-Mobile USA, Inc. and First Interstate BancSystem, Inc.

In her position as Chief Operating Officer, Ms. Taylor was responsible for the daily operations of a publicly traded telecommunications company. In this role, she led a senior management team responsible for field support, technical development, sales, marketing, customer support and information technology systems. During her 24-year tenure with Qwest and US West, she held various leadership positions responsible for strategic planning and execution, sales, marketing, product development, human resources, corporate communications and social responsibility. Ms. Taylor is keenly aware of the technical and managerial skills necessary to operate a customer service company in a complex regulatory and competitive business environment. This experience will provide valuable insights as we operate in multiple regulatory environments and develop products and customer service programs to meet the expectations of our customers.

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Board Leadership Structure and Risk Oversight

Our Corporate Governance Guidelines will not include a fixed policy with respect to combining or separating the offices of Chairman and Chief Executive Officer. If the Chairman is not an independent director, the board of directors will choose a lead director to serve as chair of the Nominating and Governance Committee and as the presiding director for purposes of the NYSE rules.

Following the Separation, Robert C. Skaggs, Jr. will hold the offices of Chairman and Chief Executive Officer. Mr. Skaggs is the director most familiar with our business and industry and is therefore best able to identify the strategic priorities to be discussed by the board of directors. Combining the role of Chairman and Chief Executive Officer facilitates information flow between management and the board of directors and fosters strategic development and execution. Prior to the Separation, the board of directors will appoint a lead independent director. The lead independent director will coordinate feedback to the Chief Executive Officer on behalf of the independent directors regarding business issues and board management. The lead independent director and the other independent directors will meet regularly without the Chief Executive Officer present.

The board of directors will take an active role in monitoring and assessing our risks, which include risks associated with operations, credit, energy supply, financing, capital investments and compensation policies and practices. The board of directors will administer its oversight function through utilization of its various committees, as well as through a Risk Management Committee, consisting of members of our senior management, which is responsible for the risk management process. Senior management will provide an annual report on our risks to our board of directors. The Audit and Risk Committee will discuss with management and the independent auditor the effect of regulatory and accounting initiatives on our financial statements and will be responsible for overseeing the risk management program generally. The Audit and Risk Committee will receive regular updates on the activities of the Risk Management Committee and any significant policy breach, if one were to occur. In addition, the Finance Committee, Human Resources and Compensation Committee and the Environmental, Safety and Sustainability Committee are each charged with overseeing the risks associated with their respective areas of responsibility.

Committees of Our Board of Directors

Upon completion of the Separation, the committees of our board of directors are expected to consist of an Audit and Risk Committee, a Human Resources and Compensation Committee, an Environmental, Safety & Sustainability Committee, a Finance Committee, and a Nominating and Governance Committee. Each of the Audit, Human Resources and Compensation and Nominating and Governance Committees will be comprised entirely of independent directors, as required by the NYSE listing standards, and meet the additional independence standards set forth in our Corporate Governance Guidelines. Our board of directors will adopt a written charter for each of these committees, which will be posted to our website prior to the Distribution Date.

Audit and Risk Committee

The Audit and Risk Committee will be established in accordance with Section 3(a)(58)(A) and Rule 10A-3 under the Exchange Act. Among other things, the Audit and Risk Committee will have the sole authority to appoint, retain or replace the independent auditors and is responsible for overseeing:

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the integrity of our financial statements;

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the independent auditors’ qualifications and independence;

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the performance of our internal audit function and the independent auditors;

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the review of related party transactions;

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the discussion of policies with respect to risk assessment and risk management;

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our compliance with legal and regulatory requirements;

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the financial plans of the Company, capital structure, investment strategy, capital budgets and financial risks;

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our dividend policy and periodic dividends;

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our corporate insurance coverage; and

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our hedging policies and exempt swap transactions.

The Audit and Risk Committee will be comprised of members such that it meets the independence requirements set forth in the NYSE listing standards and the Audit and Risk Committee charter, and the additional independence standard set forth in our Corporate Governance Guidelines. Each member of the Audit and Risk Committee will be financially literate and have accounting or financial management expertise as such terms are interpreted by our board of directors in its business judgment. None of our Audit and Risk Committee members will simultaneously serve on more than two other public company audit committees unless our board of directors specifically determines that it would not impair the ability of an existing or prospective member to serve effectively on the Audit and Risk Committee. We expect the initial members of the Audit and Risk Committee to be Marty R. Kittrell, Lester P. Silverman, Sigmund L. Cornelius and Teresa A. Taylor.

Human Resources and Compensation Committee

The Human Resources and Compensation Committee will advise our board of directors with respect to the nomination, evaluation, compensation and benefits of our executives. In that regard, the committee will:

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approve the CEO’s compensation based on the Nominating and Governance Committee’s report on the evaluation of the CEO’s performance;

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approve the compensation of the CEO’s executive direct reports;

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make recommendations to our board of directors with respect to incentive compensation plans and equity-based plans;

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approve grants and/or awards of restricted stock, stock options and other forms of equity-based compensation;

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review and approve periodically a general compensation policy for other officers of the Company and officers of its principal subsidiaries;

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recommend Company officer candidates for election by our board of directors and oversee the evaluation of management other than the CEO;

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evaluate the risks associated with our compensation policies and practices; and

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oversee equal employment opportunity and diversity initiatives.

In carrying out its duties, the Human Resources and Compensation Committee will have direct access to outside advisors, independent compensation consultants and others to assist them.

The Human Resources and Compensation Committee will be comprised entirely of independent directors, each of whom will meet the requirements set forth in the NYSE listing standards and the Human Resources and Compensation Committee charter. The members of the Human Resources and Compensation Committee will be “non-employee directors” (within the meaning of Rule 16b-3 of the Exchange Act) and “outside directors” (within the meaning of Section 162(m) of the Code). We expect the initial members of the Human Resources and Compensation Committee to be Teresa A. Taylor, Deborah S. Parker, W. Lee Nutter and Sigmund L. Cornelius.

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Environmental, Safety & Sustainability Committee

The Environmental, Safety & Sustainability Committee will assist the board of directors in overseeing the programs, performance and risks relative to environmental, safety and sustainability matters. In this regard, the committee will:

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evaluate our environmental and sustainability policies and practices;

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evaluate our safety policies and practices relating to our employees and contractors and the general public; and

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assess major legislation, regulation and other external influences that pertain to the committee’s responsibilities.

We expect the initial members of the Environmental, Safety & Sustainability Committee to be Deborah S. Parker, W. Lee Nutter, Lester P. Silverman and Marty R. Kittrell.

Nominating and Governance Committee

The Nominating and Governance Committee’s primary functions will be, among other things, to:

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recommend to our board of directors the appropriate size and composition of our board of directors or any committee thereof;

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recommend to our board of directors the compensation of directors;

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identify individuals qualified to become members of our board of directors, consistent with criteria approved by our board of directors;

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recommend to our board of directors director nominees for election at the next annual meeting of our stockholders;

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develop and recommend to our board of directors a set of corporate governance principles applicable to the Company; and

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oversee the evaluation of the performance of our board of directors and the CEO.

The Nominating and Governance Committee will be comprised entirely of independent directors, each of whom will meet the requirements set forth in the NYSE listing standards and the Nominating and Governance Committee charter, and the additional independence standards set forth in our Corporate Governance Guidelines. We expect the initial members of the Nominating and Governance Committee to be Sigmund L. Cornelius, Teresa A. Taylor, Deborah S. Parker, W. Lee Nutter, Lester P. Silverman and Marty R. Kittrell.

Following the Separation, the Nominating and Governance Committee will identify and screen candidates for director and make its recommendations for directors to the board of directors as a whole. The committee will have the authority to retain a search firm to help it identify director candidates to the extent it deems necessary or appropriate. In considering candidates for director, the committee will consider the nature of the expertise and experience required for the performance of the duties of a director of a company engaged in our businesses, as well as each candidate’s relevant business, academic and industry experience, professional background, age, current employment, community service, other board service and other factors. Pursuant to the Corporate Governance Guidelines, the committee will also consider the racial, ethnic and gender diversity of the board of directors. The committee will seek to identify and recommend candidates with a reputation for and record of integrity and good business judgment who: have experience in positions with a high degree of responsibility and are leaders in the organizations with which they are affiliated, are effective in working in complex collegial settings, are free from conflicts of interest that could interfere with a director’s duties to CPG and its stockholders and are willing and able to make the necessary commitment of time and attention required for effective service on the board of directors. The committee will also take into account the candidate’s level of financial literacy.

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The committee will monitor the mix of skills and experience of the directors in order to assess whether the board of directors has the necessary tools to perform its oversight function effectively. The committee will also assess the diversity of the board of directors as part of its annual self-assessment process. The committee will consider nominees for directors recommended by stockholders and will use the same criteria to evaluate candidates proposed by stockholders.

Compensation Committee Interlocks and Insider Participation

It is not expected that any of our executive officers will serve as a member of the board of directors or as a member of a compensation committee of any other company that has an executive officer serving as a member of our board of directors or our Human Resources and Compensation Committee.

Code of Business Conduct

Prior to the Distribution, we will adopt a Code of Business Conduct (the “Code of Conduct”) to promote (i) ethical behavior including the ethical handling of conflicts of interest, (ii) full, fair, accurate, timely and understandable financial disclosure, (iii) compliance with applicable laws, rules and regulations, (iv) accountability for adherence to the Code of Conduct and (v) prompt internal reporting of violations of the Code of Conduct. The Code of Conduct will satisfy applicable SEC and NYSE requirements and will apply to all directors, officers (including our principal executive officer, principal financial officer, principal accounting officer and controller) and employees of the Company and its affiliates. A copy of the Code of Conduct will be posted to our website immediately prior to the Distribution Date.

Any future waivers of the Code of Conduct for any director, Section 16 officer or senior executive would be made only by the Audit and Risk Committee of our board of directors and would be promptly disclosed to the extent and in the manner required by the SEC or the NYSE and posted on the Company’s website.

Corporate Governance Guidelines

The Corporate Governance Committee will be responsible for annually reviewing and reassessing the Corporate Governance Guidelines and will submit any recommended changes to our board of directors for its approval. The Corporate Governance Guidelines will be posted to our website immediately prior to the Distribution Date.

Director Compensation

In 2014, the individuals who served on the board of directors of CPG were Stephen P. Smith and Carrie J. Hightman. Because these individuals were employees of NiSource in 2014, they did not receive any additional compensation for serving as directors of CPG.

We will be asking our board of directors to approve the following non-employee director compensation for their service on our board of directors, which we believe to be consistent with market practices of other similarly situated companies and consistent with the current compensation structure applicable to directors of NiSource. Only non-employee directors will receive director compensation. Therefore, since Mr. Skaggs will be an employee of CPG, he is not expected to receive any additional compensation for his service as a board member.

We will use a combination of cash and stock-based awards to attract and retain highly qualified candidates to serve on the board of directors. We expect to pay each non-employee director an annual retainer of $240,000, consisting of $90,000 in cash and an award of restricted stock units valued at $150,000 at the time of the award. The cash retainer will be paid in arrears in four equal installments at the end of each calendar quarter. The restricted stock units are expected to be awarded annually and the number of restricted stock units will be determined by dividing the value of the annual equity retainer by the closing price of CPG’s common stock on the grant date (or, in the case of the initial grant, on the first full day of trading following the Distribution Date). Restricted stock units will be granted to directors under the Columbia Pipeline Group, Inc. 2015 Omnibus Incentive Plan (the “Omnibus Plan”). These annual retainers will be prorated in the case of a partial year of service.

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The board of directors also expects to provide additional compensation to those directors who take on additional responsibilities and serve as the chair of a board committee. The annual committee chair fees for non-employee directors are expected to be $20,000 for each of the standing committees. These fees will be paid in cash in arrears in four equal installments, and will be prorated in the case of a partial year of service.

All Other Compensation. We expect to provide our directors with matching charitable contributions made by the Columbia Pipeline Group, Inc. Charitable Foundation. We expect to match up to $10,000 annually in contributions by any director to approved tax-exempt charitable organizations, and we expect that any amount not utilized for the match in the year it is first available will be carried over to the following year.

Omnibus Plan. The Omnibus Plan will permit equity awards to be made to non-employee directors in the form of non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. The Omnibus Plan is further described in the section titled “Columbia Pipeline Group, Inc. 2015 Omnibus Incentive Plan” elsewhere in this Information Statement. Terms and conditions of awards to non-employee directors will be determined by the board of directors, based on the recommendation of the Nominating and Corporate Governance Committee, prior to grant. Awards of restricted stock units will vest and be payable in shares of common stock on the earlier of (a) the last day of the director’s annual term for which the restricted stock units are awarded or (b) the date that the director separates from service due to a “Change in Control” (as defined in the Omnibus Plan); provided, however, that in the event that the director separates from service prior to such time as a result of “Retirement” (defined as the cessation of services after providing a minimum of five continuous years of service as a member of the board of directors), death or “Disability” (as defined in the Omnibus Plan), the director’s restricted stock unit awards will pro-rata vest in an amount determined by using a fraction, where the numerator will be the number of full or partial calendar months elapsed between the grant date and the date of the director’s Retirement, death or Disability, and the denominator of which will be the number of full or partial calendar months elapsed between the grant date and the last day of the director’s annual term for which the director is elected that corresponds to the year in which the restricted stock units are awarded. The vested restricted stock units awarded will be payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s prior deferral election.

With respect to restricted stock units that have not been distributed, additional restricted stock units will be credited to each non-employee director’s bookkeeping account to reflect ordinary cash dividends paid to stockholders. The restricted stock units have no voting or other stock ownership rights and are payable in shares of our common stock upon distribution.

We expect that NiSource restricted stock units held by each of our non-employee directors on the date of Separation will convert into CPG restricted stock units in a manner that preserves the value of the award following the Separation and that such CPG restricted stock units will be on substantially the same terms and conditions as the original NiSource restricted stock units, except that any continued vesting of such CPG restricted stock units will be based on continued service with CPG.

Director Stock Ownership. The board of directors will maintain stock ownership requirements for its directors that are included in the Corporate Governance Guidelines. Within five years of becoming a non-employee director, each non-employee director will be required to hold an amount of our common stock with a value equal to five times the annual cash retainer paid to directors by CPG. Our stock that will count towards satisfaction of this requirement includes shares purchased on the open market, awards of restricted stock or restricted stock units through the Omnibus Plan, and shares beneficially owned in a trust or by a spouse or other immediate family member residing in the same household.

It is intended that each director will have a significant portion of his or her compensation directly aligned with long-term stockholder value, with 57% of the board’s annual retainer (valued as of the time of award) expected to be awarded as restricted stock units, which will be converted into common stock when distributed to the director.

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COMPENSATION DISCUSSION AND ANALYSIS

Introduction

In this Compensation Discussion and Analysis (“CD&A”), we discuss the compensation of our Chief Executive Officer, Chief Financial Officer, and our three other most highly compensated executive officers for the year ended December 31, 2014. These executive officers, whom we refer to as our “Named Executive Officers,” are set forth below, along with their titles as employees of NiSource. Please refer to the “Management” section of this Information Statement for the roles that each Named Executive Officer is expected to hold at the effective time of the Separation.

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Robert C. Skaggs, Jr., President and Chief Executive Officer of NiSource;

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Stephen P. Smith, Executive Vice President and Chief Financial Officer of NiSource;

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Glen L. Kettering, Executive Vice President and Group Chief Executive Officer of NiSource’s Columbia Pipeline Group business unit;

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Shawn L. Patterson, President of Operations and Project Delivery of NiSource’s Columbia Pipeline Group business unit; and

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Stanley G. Chapman, III, Executive Vice President and Chief Commercial Officer for various CEG subsidiaries.

We will also discuss NiSource’s historical and CPG’s anticipated executive compensation philosophy and programs following the Separation. In connection with the Separation, the board of directors of CPG will establish the Human Resources and Compensation Committee consisting entirely of independent directors. Following the Separation, the Human Resources and Compensation Committee will determine CPG’s executive compensation policies and programs. This CD&A focuses primarily on NiSource’s compensation policies and decisions for 2014 as they relate to the Named Executive Officers and the process for determining 2014 compensation while CPG was a wholly-owned subsidiary of NiSource and NiSource operated the Columbia Pipeline Group business unit. For purposes of the following discussion in this CD&A, NiSource’s Columbia Pipeline Group business unit is referred to as “NiSource CPG”.

Prior to the Separation, CPG will continue to be a wholly-owned subsidiary of NiSource, and therefore our historical compensation program is based on the compensation philosophy and programs previously established by the Officer Nomination and Compensation Committee of NiSource’s board of directors (the “NiSource ONC Committee”). For 2014, the NiSource ONC Committee determined equity-based compensation for each of the Named Executive Officers as well as the cash compensation of Messrs. Skaggs, Smith and Kettering. Because Messrs. Patterson and Chapman did not directly report to Mr. Skaggs, their cash compensation was determined by their direct manager, Mr. Kettering. Named Executive Officer compensation adjustments were based on performance evaluations performed by the Named Executive Officer’s direct manager, if applicable (Mr. Skaggs in the case of Messrs. Kettering and Smith and Mr. Kettering in the case of Messrs. Patterson and Chapman) and, in the case of Mr. Skaggs, a performance evaluation performed by the Corporate Governance Committee of NiSource’s board of directors, with input from NiSource’s Senior Vice President of Human Resources, competitive market data and, in the case of Messrs. Skaggs, Smith and Kettering, input from the NiSource ONC Committee’s independent compensation consultant, Exequity LLP.

CPG’s Executive Compensation Philosophy and Programs Following the Separation

The Human Resources and Compensation Committee has not yet been established and therefore has not established a specific set of objectives or principles for CPG’s executive compensation program following the Separation. It is anticipated that the Human Resources and Compensation Committee will establish objectives and principles similar to the objectives and principles that NiSource maintained for its compensation program in 2014, as described in this CD&A.

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It is anticipated that CPG’s general executive compensation philosophy will focus on providing programs that attract, retain and motivate employees in a way that aligns with CPG’s business strategies to drive stockholder value. Our post-Separation compensation programs will be designed to pay for performance and focus on the achievement of specified business objectives. We expect that CPG’s executive compensation program will provide a total compensation package that is competitive with prevailing practices and allows for increased compensation when superior financial performance is achieved, but does not encourage unnecessary and excessive risk taking that could adversely affect CPG and its stockholders.

CPG’s compensation programs and practices that will be implemented in connection with the Separation will be designed to support CPG’s compensation philosophy as described above and may differ from NiSource’s compensation programs and practices. See the section below entitled “Anticipated Compensation Programs Following the Separation” for a description of the anticipated post-Separation compensation elements.

Overview of the 2014 Executive Compensation Program

The primary objectives of the 2014 executive compensation program applicable to the Named Executive Officers were to attract, retain and motivate highly qualified executives.

The principal elements of compensation received by the Named Executive Officers in 2014 were: base salary, annual short-term performance-based cash incentives and long-term performance-based equity incentive awards (taken together these three elements are referred to as “total compensation”). Total compensation is generally targeted to be competitive with the compensation paid to similarly positioned executives at companies within NiSource’s peer group of companies (the “NiSource Comparative Group”) as described below under the heading “Executive Compensation Process—Competitive Market Review.” NiSource also considers general industry survey data in evaluating compensation decisions. NiSource does not, however, manage pay to a certain target percentile of the NiSource Comparative Group or general industry survey data.

NiSource uses short and long-term performance-based compensation to motivate executives, including the Named Executive Officers, to meet and exceed short and long-term business objectives for NiSource and NiSource CPG. For 2014, NiSource delivered 100% of its annual long-term equity incentive awards as performance-based equity as a means to align the interests of executives with those of its stockholders. In addition, NiSource occasionally uses special awards of time-vested restricted stock and restricted stock units to attract and retain executive talent, promote management continuity and reward outstanding performance.

NiSource employs leading governance practices, such as clawback policies and stock ownership guidelines for its executive officers, and conducts an annual risk assessment of its compensation practices. In addition, NiSource’s executive officers are prohibited from trading in NiSource securities during quarterly blackout periods, and they are prohibited from engaging in hedging or short sales of NiSource’s equity securities.

Executive Compensation Highlights

In connection with its ongoing review of NiSource’s executive compensation program, the NiSource ONC Committee made a number of compensation decisions with respect to 2014 that impacted the compensation received by the Named Executive Officers as follows:

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Approved base salary increases for each of the Named Executive Officers for the reasons explained below under the heading “Actions Related to 2014 Compensation—2014 Base Salaries;”

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Approved an increase in the trigger, target and stretch award opportunities for the annual cash short-term incentive for Mr. Skaggs for the reasons explained below under the heading “Actions Related to 2014 Compensation—Annual Performance-Based Cash Incentives;”

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Delivered the 2014 annual long-term equity incentive awards to the Named Executive Officers solely in the form of performance shares that vest upon the achievement of pre-established performance goals and the executive’s continued employment over the multi-year performance period;

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Further aligned the performance goals for the 2014 annual long-term equity incentive awards with NiSource’s strategic operating plan and with the interests of NiSource’s shareholders by removing “funds from operations” as a performance goal under the 2014 annual long-term equity incentive program and substantially increasing the weighting for relative total shareholder return;

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Approved increases in the grant value of the 2014 annual long-term equity incentive awards for Messrs. Skaggs, Smith, Patterson and Chapman, as discussed below under the heading “Actions Related to 2014 Compensation—LTIP Awards;”

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Awarded Mr. Kettering a special cash bonus of $100,000 and a special grant of time-vested restricted stock units with a grant date fair value of $500,000 in recognition of his role as interim Group Chief Executive Officer for NiSource CPG;

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Entered into a cash retention bonus agreement with Mr. Patterson providing for cash retention bonuses in the aggregate amount of $500,000 and payable over a four-year period subject to his continued employment and awarded Mr. Patterson a special one-time grant of time-vested restricted stock units with a grant date fair value of $1,500,000, each for retention purposes;

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Entered into a cash retention bonus agreement with Mr. Chapman providing for cash retention bonuses in the aggregate amount of $300,000 and payable over a three-year period subject to his continued employment and awarded Mr. Chapman a special one-time grant of time-vested restricted stock units with a grant date fair value of $1,051,500, each for retention purposes;

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Approved discretionary cash bonuses for each of the Named Executive Officers based on his significant contributions to NiSource’s success as further explained below under the heading “Actions Related to 2014 Compensation—Additional Discretionary Lump Sum Payouts to the Named Executive Officers Based on 2014 Performance;”

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Approved a change to the NiSource 2014 restricted stock and restricted stock unit awards so that change-in-control vesting is contingent on the occurrence of both a qualifying change-in-control and employment termination; and

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Modified the NiSource Comparative Group (as defined below) to further align NiSource with companies that are operationally similar and with which NiSource competes for executive talent.

Executive Compensation Philosophy

The key design priorities of the 2014 executive compensation program applicable to the Named Executive Officers were to:

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Maintain a financially responsible program aligned with NiSource’s strategic plan to build stockholder value and long-term, sustainable earnings growth;

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Provide a total compensation package that is aligned with the standards within NiSource’s industry thereby enhancing NiSource’s and CPG’s ability to:

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Attract and retain executives with competitive compensation opportunities;

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Motivate and reward for achieving and exceeding business objectives; and

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Provide substantial portions of pay at risk for failure to achieve business objectives;

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Align the interests of stockholders and executives by emphasizing stock-denominated compensation opportunities that are contingent on goal achievement; and

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Comply with all applicable laws and regulations.

The NiSource ONC Committee and NiSource CPG management believe that the Named Executive Officer compensation program is thoughtfully and effectively constructed to fulfill the compensation objectives of NiSource and CPG and rewards decision-making that creates value for our stockholders, customers and other key stakeholders.

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Principal Elements of 2014 Compensation Program

The executive compensation program has been designed to meet business objectives with the use of various executive compensation elements intended to drive both short-term and long-term performance.

NiSource believes that total compensation for executive officers should be largely performance-based and the proportion of at-risk, performance-based compensation should increase as the executive’s level of responsibility within the organization increases. The NiSource ONC Committee and NiSource CPG management believe that the appropriate mix of compensation elements should take into account business objectives, the competitive environment, company performance, individual performance and responsibilities, and evolving governance practices.

The principal elements of the 2014 total compensation package provided to the Named Executive Officers, as more fully described below, help NiSource and NiSource CPG achieve the compensation program objectives as follows:

Element of Total Compensation

Form of
Compensation

Attraction

Time Horizon

Alignment
with
Stockholder
Interest

Retention

Short-Term

Long-Term

Base Salary

Cash

Annual Performance-Based Cash Incentive

Cash

Long-Term Performance-Based Equity Incentive

Performance

Base Salary. Base salary is designed to provide employees with a level of fixed pay that is commensurate with role and responsibility. NiSource believes that by delivering base salaries that are reflective of market norms, NiSource and CPG are well-positioned to attract, retain and motivate top caliber executives in an increasingly competitive labor environment. Base salaries are annually reviewed by the NiSource ONC Committee with respect to Messrs. Skaggs, Smith and Kettering and by Mr. Kettering with respect to Messrs. Patterson and Chapman. In evaluating base salaries, the NiSource ONC Committee considers whether base salaries are competitive within the industry and evaluates the base salaries paid to similarly situated executives by the companies in the NiSource Comparative Group. See the discussion below under the heading “Executive Compensation Process—Competitive Market Review” listing the companies in the NiSource Comparative Group. Any base salary changes for the Named Executive Officers are determined based on a combination of factors, including competitive pay standards, level of responsibility, experience, internal equity considerations, historical compensation, and individual performance and contribution to business objectives. See the section below entitled “Actions Related to 2014 Compensation” for more information regarding 2014 base salary adjustments for the Named Executive Officers.

Annual Performance-Based Cash Incentive Plan (“Incentive Plan”). This component of total compensation provides employees with the opportunity to earn a cash award tied to both annual company performance and individual contributions. The performance goals for the Incentive Plan are based on the financial plan approved at the beginning of the year by the NiSource board of directors and, in the case of the business goals applicable to NiSource CPG, Mr. Skaggs. The financial plan is designed to support NiSource’s aim of creating sustainable stockholder value by growing earnings, effectively managing cash and providing a strong dividend.

Every participant has an incentive opportunity at trigger, target and stretch levels of performance established by the NiSource ONC Committee or, in the case of Messrs. Patterson and Chapman, Mr. Kettering. See the section below entitled “Actions Related to 2014 Compensation” for more information regarding the 2014 Incentive Plan, including incentive opportunities, performance measures, goals and payouts for each of the Named Executive Officers.

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Long-Term Equity Incentive Plan (“LTIP”). NiSource’s compensation program also includes a long-term equity incentive component. The NiSource ONC Committee believes it is important that each executive, in particular each of the senior executives within the NiSource organization, has personal financial exposure to the performance of NiSource’s stock and, therefore, is aligned with the financial interests of stockholders. The NiSource ONC Committee also believes that long-term equity incentives promote decision making that is consistent with long-range operating goals.

To align the interests of executives with those of NiSource’s stockholders and its long-term business objectives, the NiSource ONC Committee determined that the annual long-term equity incentive awards will be delivered solely in performance shares. Performance shares provide the opportunity to earn shares of NiSource’s common stock contingent on the achievement of multi-year performance goals that NiSource believes drive stockholder value. The number of performance shares that can be earned ranges from 50% of target when performance reaches the trigger level to 200% of target when performance reaches the maximum creditable level of results.

When establishing award opportunity levels for each of the Named Executive Officers, the NiSource ONC Committee considers, among other things, the executive’s base salary, the appropriate mix of cash and equity award opportunities, prior awards under the LTIP and the compensation practices for similarly situated executives at other companies in the NiSource Comparative Group. In addition, in the case of Messrs. Patterson and Chapman, the NiSource ONC Committee considered the recommendations of Mr. Skaggs, which reflect input from NiSource’s Senior Vice President of Human Resources and Mr. Kettering. The actual value of each performance-based award, if any, depends on NiSource performance against pre-established performance measures as well as the NiSource stock price at the time the award is paid out.

The NiSource ONC Committee may also approve special equity awards that are not performance-based to attract and retain executive talent or to recognize significant contributions to the organization. See the section below entitled “Actions Related to 2014 Compensation” for more information regarding the 2014 LTIP awards for each of the Named Executive Officers, including the performance measures and goals and vesting requirements for the 2014 performance share awards, Mr. Kettering’s 2014 equity award in recognition of his role as interim Group Chief Executive Officer for NiSource CPG, Messrs. Patterson’s and Chapman’s 2014 equity awards granted for retention purposes, and the performance results and payout amounts for the 2012 performance share awards.

NiSource equity awards that are outstanding when the Separation occurs are expected to be adjusted in an equitable manner, as described under the heading “Treatment of Equity—Based Compensation” on page 65 of this Information Statement.

Other Compensation and Benefits

NiSource also provides other forms of compensation to executives, including the Named Executive Officers, consisting of a limited number of perquisites, severance and change-in-control arrangements and a number of other employee benefits that generally are extended to NiSource’s entire employee population. These other forms of compensation are generally comparable to those that are provided to similarly situated executives at other companies of NiSource’s size. After the Separation, CPG expects to also provide similar compensation arrangements and benefit plans to its executives. See the section below entitled “Anticipated Compensation Programs Following the Separation” for a description of the anticipated post-Separation compensation elements.

Perquisites. Perquisites are not a principal element of NiSource’s executive compensation program. They are intended to assist NiSource’s executive officers in the performance of their duties or otherwise to provide benefits that have a combined personal and business purpose. NiSource does not reimburse executive officers for the payment of personal income taxes incurred by the executives in connection with their receipt of these benefits. For more information on these perquisites, see the Summary Compensation Table and footnote 6 to that table.

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Severance and Change-In-Control Benefits. NiSource maintains an executive severance policy and Change-in-Control Agreements with all of the Named Executive Officers, and a letter agreement with Mr. Smith regarding payments to be made in the event of termination of his employment. Change-in-Control Agreements are intended to ensure that thoroughly objective judgments are made in relation to any potential change in corporate ownership so that stockholder value is appropriately safeguarded and returns to investors are maximized. The Change-in-Control Agreements provide for cash severance benefits upon a double trigger (meaning there must be both a change-in-control and qualifying termination of employment) and do not provide for any “gross-up” payments to executives for excise taxes incurred with respect to benefits received under a Change-in-Control Agreement.

For a further discussion of these agreements, see the “Potential Payments upon Termination of Employment or a Change-in-Control of the Company” table and the accompanying narrative.

Pension Programs. During 2014, NiSource maintained a tax-qualified defined benefit pension plan for essentially all salaried exempt employees hired before January 1, 2010 and all non-exempt employees (both non-union and certain union employees) hired before January 1, 2013, as well as for other union employees, regardless of hire date and a non-qualified defined benefit pension plan (the “Pension Restoration Plan”) for all eligible employees with annual compensation or pension benefits in excess of the limits imposed by the IRS, including the Named Executive Officers. The Pension Restoration Plan provides for a pension benefit under the same formula provided under the tax-qualified plan but without regard to the IRS limits reduced by amounts paid under the tax-qualified plan. The material terms of the pension programs are described in the narrative to the Pension Benefits table.

Savings Programs. The Named Executive Officers are eligible to participate in the same tax-qualified 401(k) Plan as most NiSource employees and in a non-qualified defined contribution plan (the “Savings Restoration Plan”) maintained for eligible executive employees. The 401(k) Plan includes a company match that varies depending on the pension plan in which the employee participates and a company profit sharing contribution for most employees of between 0.5% and 1.5% of the employee’s eligible earnings based on the overall corporate net operating earnings per share measure. In addition, for salaried employees hired after January 1, 2010, the 401(k) Plan includes a 3% company contribution to the employee accounts. The Savings Restoration Plan provides for company contributions in excess of IRS limits under the 401(k) Plan for eligible employees, including the Named Executive Officers. The material terms of the Savings Restoration Plan are described in the narrative to the Non-qualified Deferred Compensation table.

Deferred Compensation Plan. NiSource also maintains the Executive Deferred Compensation Plan (the “Deferred Compensation Plan”) through which eligible executives, including the Named Executive Officers, may elect to defer between 5% and 80% of their base salary and annual cash incentive payout. NiSource makes the Deferred Compensation Plan available to eligible executives so they have the opportunity to defer their cash compensation without regard to the limits imposed by the IRS for amounts that may be deferred under the 401(k) Plan. The material terms of the Deferred Compensation Plan are described in the narrative to the Non-qualified Deferred Compensation table.

Health and Welfare Benefits. NiSource also provides other broad-based benefits such as medical, dental, life insurance and long-term disability coverage on the same terms and conditions to all employees, including the Named Executive Officers. NiSource believes that these broad-based benefits serve the objectives of its compensation program to attract, retain and motivate its employees.

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Executive Compensation Process

During 2014, the NiSource ONC Committee, with respect to Messrs. Skaggs, Smith and Kettering, and Mr. Kettering, with respect to Messrs. Patterson and Chapman, were responsible for determining salaries, performance-based incentives and other matters related to the compensation of the Named Executive Officers, and the NiSource ONC Committee was responsible for overseeing the administration of NiSource’s equity plans, including equity award grants to the Named Executive Officers. Various factors are considered when making compensation decisions, including:

•

Attainment of established business and financial goals;

•

Competitiveness of the compensation program based upon competitive market data; and

•

An executive’s position, level of responsibility and performance, as measured by the individual’s contribution to the achievement of business objectives.

Named Executive Officer compensation adjustments were based on performance evaluations performed by the Named Executive Officer’s direct manager, if applicable (Mr. Skaggs in the case of Messrs. Kettering and Smith and Mr. Kettering in the case of Messrs. Patterson and Chapman) and, in the case of Mr. Skaggs, a performance evaluation performed by the Corporate Governance Committee of NiSource’s board of directors, with input from NiSource’s Senior Vice President of Human Resources, competitive market data and, in the case of Messrs. Skaggs, Smith and Kettering, input from the NiSource ONC Committee’s independent compensation consultant, Exequity LLP. The NiSource ONC Committee engaged Exequity LLP to advise it with respect to executive compensation design, comparative compensation practices and compensation matters relating to the NiSource board of directors. Exequity LLP provides no other services to NiSource or CPG.

Competitive Market Review. In connection with its compensation decision making, the NiSource ONC Committee reviewed the executive compensation practices in effect at other companies in the NiSource Comparative Group. These companies comprise leading gas, electric, combination utility and natural gas transmission companies that have been selected by the NiSource ONC Committee for their operational comparability to NiSource and because NiSource generally competes with these companies for the same executive talent. For 2014, the NiSource ONC Committee, with input from Exequity LLP, removed PG&E Corporation, PNM Resources, Inc., and Southern Company from the NiSource Comparative Group and added Spectra Energy Corp. These modifications were made to further align the NiSource Comparative Group with NiSource with respect to revenue size, market capitalization and operational similarity. For purposes of evaluating 2014 compensation decisions with respect to Messrs. Skaggs, Smith and Kettering, the NiSource Comparative Group included the following companies:


AGL Resources Inc.		Pepco Holdings, Inc.
Ameren Corporation		PPL Corporation
American Electric Power Company, Inc.		Public Service Enterprise Group Incorporated
CenterPoint Energy, Inc.		Questar Corporation
CMS Energy Corporation		SCANA Corporation
Dominion Resources, Inc.		Sempra Energy
DTE Energy Company		Spectra Energy Corp
EQT Corporation		WGL Holdings, Inc.
FirstEnergy Corp.		The Williams Companies, Inc.

In evaluating the compensation information for Messrs. Patterson and Chapman, Mr. Kettering considered general industry survey data to obtain a general understanding of the competitive environment for such positions.

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Policies and Guidelines. NiSource maintains various guidelines and policies to help it meet its compensation objectives including:

•

Executive Stock Ownership and Retention Guidelines. Senior executives are generally expected to satisfy their applicable ownership guidelines within five years of becoming subject to the guidelines. The stock ownership guideline for Mr. Skaggs is shares of NiSource’s common stock having a value equal to five times his annual base salary. The stock ownership guideline for Messrs. Smith and Kettering is shares of NiSource’s common stock having a value equal to three times their respective annual base salaries. Once senior executives satisfy the guidelines, they must continue to own a sufficient number of shares to remain in compliance with the guidelines. Until such time as the senior executives satisfy the stock ownership guidelines, they are required to hold at least 50% of the shares of common stock received upon the lapse of the restrictions on restricted stock units and the vesting of performance shares. As of December 31, 2014, Messrs. Skaggs, Smith and Kettering had exceeded their ownership guidelines. During 2014, Messrs. Patterson and Chapman were not subject to stock ownership guidelines.

•

Hedging/Pledging. Under NiSource’s Securities Transaction Compliance Policy for Certain Employees and its Securities Transaction Compliance Policy for Directors and Executive Officers, all directors and all senior executives, including the Named Executive Officers, are prohibited from engaging in short sales of NiSource’s equity securities or in buying or selling puts, calls or other options on NiSource’s securities or otherwise hedging against or speculating in the potential changes in the value of NiSource’s common stock. None of the Named Executive Officers owns NiSource securities that are pledged.

•

Compensation Recovery for Misconduct. NiSource’s Incentive Plan, the NiSource Inc. 2010 Omnibus Incentive Plan and its predecessor, the 1994 Long-Term Incentive Plan, contain “clawback” provisions that require reimbursement of amounts received under the plans in the event of certain acts of misconduct with respect to both the annual short-term cash incentive and long-term equity awards.

Actions Related to 2014 Compensation

During 2014, the NiSource ONC Committee and Mr. Kettering, as applicable, reviewed and, as appropriate, took action with respect to each element of total compensation for each Named Executive Officer following the principles, practices and processes described above. In doing so, the NiSource ONC Committee and Mr. Kettering (with respect to Messrs. Patterson and Chapman) concluded that the total compensation provided for each of the Named Executive Officers was consistent with NiSource’s compensation philosophy and reasonable, competitive and appropriate. The compensation determinations, though subjective in part, were based primarily upon the recognition of the performance of each Named Executive Officer, and a determination that the total compensation awarded to each Named Executive Officer provided well-balanced incentives to each person to continue their employment and to focus on serving the interests of NiSource and its stockholders.

2014 Base Salaries. Historically, base salaries of senior executives within the NiSource organization, including the Named Executive Officers, have been adjusted when deemed necessary to maintain competitiveness and reflect performance. In 2014, the Named Executive Officers received base salary increases, as noted in the table below. In approving base salary adjustments, the NiSource ONC Committee and Mr. Kettering (with respect to Messrs. Patterson and Chapman) considered increased responsibilities, experience, internal pay equity, historical compensation practices, individual performance and contributions to the achievement of business objectives. For Messrs. Skaggs, Smith and Kettering the NiSource ONC Committee also considered the base salary levels for similarly situated executives at companies within the NiSource Comparative Group. In particular, the NiSource ONC Committee noted Mr. Kettering’s increased responsibilities as Executive Vice President and Group Chief Executive Officer of NiSource CPG and the fact that there had been no salary increases for Messrs. Skaggs, Smith and Kettering since 2012.

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Accordingly, the 2014 annual base salary adjustments for the Named Executive Officers were as follows:


Named Executive Officer	2013 Annual Salary		2014 Annual Salary
Robert C. Skaggs, Jr.	$	900,000	$	980,000
Stephen P. Smith	$	575,000	$	600,000
Glen L. Kettering	$	340,000	$	500,000
Shawn L. Patterson	$	337,000	$	360,000
Stanley G. Chapman, III	$	328,878	$	395,000

Annual Performance-Based Cash Incentives. In January 2014, the NiSource ONC Committee and Mr. Skaggs (in the case of the performance goals applicable to NiSource CPG) established performance measures to be used in the determination of the 2014 incentive payouts to the Named Executive Officers. In determining incentive compensation ranges for Messrs. Skaggs, Smith and Kettering, the NiSource ONC Committee considered competitive information from the NiSource Comparative Group, input from the independent compensation consultant, historical payouts and individual performance and determined that the cash-based incentive compensation range for Mr. Skaggs should be increased to a target of 125% from 100%. Mr. Skaggs’ trigger and stretch amounts were increased to 50% and 200%, respectively, from 40% and 160% after considering his strong leadership and an evaluation of the competitive market data, including a recognition that Mr. Skaggs’ target cash compensation remained below the market median.

The 2014 Incentive Plan awards for the Named Executive Officers were subject to achievement with respect to two NiSource corporate financial goals (net operating earnings per share and corporate funds from operations) and, in the case of Messrs. Skaggs, Smith and Kettering, an additional operational measure relating to safety. In addition, as executives of a business unit during 2014, the 2014 Incentive Plan awards for Messrs. Kettering, Patterson and Chapman were also subject to achievement with respect to NiSource CPG’s net operating earnings (net of interest expense and income taxes) and funds from operations. Mr. Kettering’s 2014 Incentive Plan award was also subject to a NiSource CPG-related safety goal. The NiSource ONC Committee and Mr. Skaggs (in the case of the NiSource CPG performance goals) approved these measures because they were deemed to be important to NiSource’s success in increasing stockholder value. The NiSource ONC Committee believes that the inclusion of business unit goals in the annual Incentive Plan improves the line of sight between employees and the incentive measures, thereby enhancing NiSource’s performance. The NiSource ONC Committee extended to Mr. Skaggs the authority to establish the annual NiSource CPG targets for the year. He assigned goals that, if accomplished, were expected to ensure NiSource’s attainment of its overall corporate objectives.

For purposes of the 2014 Incentive Plan, earnings, cash flow and safety were measured as follows:

•

The measure of earnings was net operating earnings per share (after accounting for the cost of any incentive payout). Net operating earnings was defined as income from continuing operations determined in accordance with GAAP, adjusted for certain items, such as weather, gains and losses on the sale of assets, certain out-of-period items and reserve adjustments. The NiSource ONC Committee uses net operating earnings, a non-GAAP financial measure, for determining financial performance for incentive compensation plans because the NiSource ONC Committee and management believe this measure better represents the fundamental earnings strength and performance of NiSource and NiSource CPG. NiSource uses net operating earnings internally for budgeting and for reporting to the board of directors.

•

The cash flow measure, corporate funds from operations, was calculated by taking net income from operations and adding back non-cash items such as depreciation. The NiSource ONC Committee uses corporate funds from operations as an Incentive Plan measure because the NiSource ONC Committee and management believe this measure fairly represents the amount of cash produced by operations.

•

Safety for NiSource was measured by the number of employee work days missed or restricted or the number of days an employee was transferred, known as the DART metric, which was developed by OSHA.

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•

In the case of Mr. Kettering, safety for NiSource CPG was measured by the number of employee work days missed or restricted or the number of days an employee was transferred, known as the DART metric, which was developed by OSHA.

The applicable performance measures and their associated weightings and results as a percentage of the target incentive opportunity for Mr. Skaggs and Mr. Smith were:


Corporate Measures⁽¹⁾	Weight			Trigger		Target		Stretch		Result			Robert C. Skaggs, Jr.				Stephen P. Smith
													Formulaic Amounts⁽²⁾				Formulaic Amounts⁽²⁾
													Payout as a % of Target		Weighted Adjusted Payout as a % of Target		Payout as a % of Target		Weighted Adjusted Payout as a % of Target
NiSource Net Operating Earnings Per Share		50	%	$	1.61	$	1.66	$	1.71	$	1.72			160%		80%		157.14%		78.57%
NiSource Funds from Operations		40	%	$	1,205M	$	1,355M	$	1,505M	$	1,456M	⁽³⁾		140.40%		56.16%		138.48%		55.39%
NiSource Safety		10	%		.79 days		.71 days		—		.76 days			37.50%		3.75%		37.50%		3.75%

(1)

When the result for a particular measure lands between two goals (for example, between the target and stretch goal), the incentive opportunity is determined by interpolation and is expressed as a percentage of the target incentive opportunity. Interpolation for the safety goal only applies between trigger and target. Consequently, target is the maximum available level for the safety goal.

(2)	These amounts reflect a percentage of each executive’s target incentive opportunity, as discussed further below.

(3)	This includes an upward adjustment of $92.4 million to Funds from Operations (for NiSource), taking into consideration the impact of non-recurring items, such as incremental pension expense subsidized by NiSource and changes in accounting.

The applicable performance measures and their associated weightings and results as a percentage of the target incentive opportunity for Mr. Kettering were:


Corporate Measures⁽¹⁾	Weight			Trigger		Target		Stretch		Results			Formulaic Payout as a % of Target⁽²⁾		Weighted Adjusted Formulaic Payout as a % of Target⁽²⁾
NiSource Net Operating Earnings Per Share		25	%	$	1.61	$	1.66	$	1.71	$	1.72			158.33%		39.58%
NiSource Funds from Operations		20	%	$	1,205M	$	1,355M	$	1,505M	$	1,456M	⁽³⁾		139.28%		27.86%
NiSource CPG Safety		10	%		.25 days		.19 days		—		.09 days			100.00%		10.00%
NiSource CPG Net Operating Earnings		22.50	%	$	264M	$	269M	$	279M	$	274M	⁽⁴⁾		129.17%		29.06%
NiSource CPG Funds from Operations		22.50	%	$	397M	$	440M	$	483M	$	527M	⁽⁵⁾		158.33%		35.63%

(1)

When the result for a particular measure lands between two goals (for example, between the target and stretch goal), the incentive opportunity is determined by interpolation and is expressed as a percentage of the target opportunity. Interpolation for the safety goal only applies between trigger and target. Consequently, target is the maximum available level for the safety goal.

(2)	These amounts reflect a percentage of Mr. Kettering’s target incentive opportunity, as discussed further below.

(3)	This includes an upward adjustment of $92.4 million to Funds from Operations (for NiSource), taking into consideration the impact of non-recurring items, such as incremental pension expense subsidized by NiSource and changes in accounting.

(4)	This includes an upward adjustment of $9.8 million to Net Operating Earnings (for NiSource CPG), taking into consideration the impact of changes in tax law, and the impact of non-recurring items such as incremental pension expense subsidized by NiSource and other changes in accounting.

(5)	This includes an upward adjustment of $38.6 million to Funds from Operations (for NiSource CPG), taking into consideration the impact of non-recurring items such as incremental pension expense subsidized by NiSource and changes in accounting.

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The applicable performance measures and their associated weightings and results as a percentage of the target incentive opportunity for Mr. Patterson and Mr. Chapman were:


Corporate Measures⁽¹⁾	Weight			Trigger		Target		Stretch		Result			Shawn L. Patterson				Stanley G. Chapman, III
													Formulaic Amounts⁽²⁾				Formulaic Amounts⁽²⁾
													Payout As a % of Target		Weighted Adjusted Payout as a % of Target		Payout As a % of Target		Weighted Adjusted Payout as a % of Target
NiSource Net Operating Earnings Per Share		25	%	$	1.61	$	1.66	$	1.71	$	1.72			150.00%		37.50%		150.00%		37.50%
NiSource CPG Net Operating Earnings		37.50	%	$	264M	$	269M	$	279M	$	274M	⁽³⁾		125.00%		46.88%		125.00%		46.88%
NiSource CPG Funds from Operations		37.50	%	$	397M	$	440M	$	483M	$	527M	⁽⁴⁾		150.00%		56.25%		150.00%		56.25%

(1)

When the result for a particular measure lands between two goals (for example, between the target and stretch goal), the incentive opportunity is determined by interpolation and is expressed as a percentage of the target opportunity. Interpolation for the safety goal only applies between trigger and target. Consequently, target is the maximum available level for the safety goal.

(2)	These amounts reflect a percentage of each executive’s target incentive opportunity, as discussed further below.

(3)	This includes an upward adjustment of $9.8 million to Net Operating Earnings (for NiSource CPG), taking into consideration the impact of changes in tax law, and the impact of non-recurring items such as incremental pension expense subsidized by NiSource and other changes in accounting.

(4)	This includes an upward adjustment of $38.6 million to Funds from Operations (for NiSource CPG), taking into consideration the impact of non-recurring items, such as incremental pension expense subsidized by NiSource and changes in accounting.

2014 Incentive Plan Payouts to the Named Executive Officers. For 2014, the annual incentive opportunities and actual payout amounts for each of the Named Executive Officers were:


Named Executive Officer	Trigger (% of Salary)			Target (% of Salary)			Stretch (% of Salary)			2014 Award (% of Target)			2014 Award⁽¹⁾
Robert C. Skaggs, Jr.		50	%		125	%		200	%		140	%	$	1,715,000
Stephen P. Smith		30	%		70	%		110	%		138	%	$	579,600
Glen L. Kettering		25	%		60	%		95	%		142	%	$	426,000
Shawn L. Patterson		25	%		50	%		75	%		141	%	$	247,044
Stanley G. Chapman, III		25	%		50	%		75	%		141	%	$	272,600

(1)	The 2014 Awards for each of the Named Executive Officers were calculated as follows: annual base salary multiplied by his Target (% of Salary) multiplied by the applicable 2014 Award (% of Target).

In January 2015, the NiSource ONC Committee certified the performance results set forth in the tables above. The NiSource ONC Committee determined it was appropriate to approve an Incentive Plan payout of $1,715,000 to Mr. Skaggs based on NiSource’s above-target performance relative to the net operating earnings per share financial metric and funds from operations financial metric as well as his continued strong leadership in 2014. Mr. Skaggs also made recommendations to the NiSource ONC Committee with respect to the award of Incentive Plan payouts to Messrs. Kettering and Smith. In making his recommendations, Mr. Skaggs considered NiSource’s performance and the performance of the senior executives in delivering strong stockholder returns again in 2014, as well as the performances of the business unit and corporate functions the executives led. The NiSource ONC Committee considered and accepted Mr. Skaggs’ recommendations and approved Incentive Plan payouts to Messrs. Smith and Kettering in accordance with the Incentive Plan formula, as set forth in the table above. With respect to Messrs. Patterson and Chapman, Mr. Kettering approved their respective Incentive Plan payouts after considering the performance results certified by the NiSource ONC Committee as well as NiSource CPG’s performance and the performance of the senior executives.

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2014 Discretionary Lump Sum Payout to Mr. Kettering. In January 2014, the NiSource ONC Committee also awarded Mr. Kettering a special cash bonus award of $100,000 in recognition of his role as interim Group Chief Executive Officer of NiSource CPG. This bonus amount is set forth in the Bonus column of the Summary Compensation Table because it was not based on performance relative solely to the pre-established performance criteria under the Incentive Plan.

Additional Discretionary Lump Sum Payouts to the Named Executive Officers Based on 2014 Performance. In January 2015, the NiSource ONC Committee exercised its discretion to award bonuses to each of the Named Executive Officers in addition to amounts based on performance relative to pre-established performance criteria described above under the section entitled “Incentive Plan.” The NiSource ONC Committee approved a discretionary bonus of $1,785,000 for Mr. Skaggs based on NiSource’s consistently superior performance over the last several years under his stewardship, including 207% cumulative total shareholder return over the past five years and Mr. Skaggs’ strategic leadership in developing and executing on the decision to create the MLP and to separate NiSource CPG into a stand-alone publicly traded company.

In addition, the NiSource ONC Committee approved discretionary bonuses of $750,000 for Mr. Smith, and $500,000 for Mr. Kettering based on their significant contributions to the development and execution of the decision to create the MLP and to separate NiSource CPG into a stand-alone publicly traded company. In particular, the NiSource ONC Committee considered Mr. Smith’s and Mr. Kettering’s key roles in developing and executing on the formation of the MLP and the Separation, including strategic and financial analysis, transition analysis and preparation. Mr. Kettering also approved discretionary bonuses of $100,000 and $110,000 for Mr. Patterson and Mr. Chapman, respectively, based on their leadership in developing a number of significant CPG growth projects and in executing on CPG’s substantial 2014 capital program.

The amounts of these discretionary bonuses are included in the amount set forth in the Bonus column of the Summary Compensation Table because they are in addition to the amounts based on performance relative to the pre-established performance criteria under the Incentive Plan, described above, which are set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

2014 Special Retention Bonuses. In March 2014, NiSource entered into a retention bonus agreement with Mr. Patterson under which Mr. Patterson is eligible to receive cash retention bonuses in the aggregate amount of $500,000, with the first bonus of $100,000 paid on March 31, 2014 and the second and third installments of $200,000 each to be paid within 30 days following March 31, 2016 and March 31, 2018, respectively, subject to Mr. Patterson’s continued employment with NiSource or one of its affiliates or subsidiaries, or their successors, through the applicable vesting date.

Pursuant to a November 2011 employment offer letter with Mr. Chapman, Mr. Chapman received a $100,000 retention bonus in December 2014. In addition, in September 2014, NiSource entered into a retention bonus agreement with Mr. Chapman under which Mr. Chapman is eligible to receive cash retention bonuses of $100,000 each to be paid within 30 days following December 1, 2015, December 1, 2016 and December 1, 2017, respectively, subject to Mr. Chapman’s continued employment with NiSource or one of its affiliates or subsidiaries, or their successors, through the applicable vesting date.

The amounts of these retention bonuses paid in 2014 to Messrs. Patterson and Chapman are included in the amount set forth in the Bonus column of the Summary Compensation Table because they are in addition to the amounts based on performance relative to the pre-established performance criteria under the Incentive Plan, described above, which are set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

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LTIP Awards

2014 Performance Share Awards. In January 2014, the NiSource ONC Committee approved a grant of performance shares to senior executives, including each of the Named Executive Officers. In determining the 2014 long-term incentive grant values to be awarded to Messrs. Skaggs, Smith and Kettering, the NiSource ONC Committee considered competitive pay practices at companies within the NiSource Comparative Group, input from its independent compensation consultant, NiSource’s historical mix of fixed compensation verses variable incentive compensation, and individual performance and leadership. With respect to the 2014 long-term incentive awards for Messrs. Patterson and Chapman, the NiSource ONC Committee considered the recommendations of Mr. Skaggs, which considered input from NiSource’s Senior Vice President of Human Resources and an assessment of individual performance and leadership performed by Mr. Kettering. In approving the 2014 long-term incentive awards, the NiSource ONC Committee considered the continued strong leadership of Mr. Skaggs and Mr. Smith in addition to the appropriateness of market adjustments for Mr. Skaggs based on competitive pay practices at companies within the NiSource Comparative Group. As a result of its review, the NiSource ONC Committee approved an increase for 2014 grant values for Messrs. Skaggs and Smith that were approximately 25% and 8% greater than their prior year’s award values, respectively, and increased the grant values for Messrs. Patterson and Chapman by approximately 12.5% and 45% as compared to the prior year’s award value, respectively. The NiSource ONC Committee also eliminated funds from operations as a performance measure for the 2014 grant of performance shares in order to further align the 2014 performance shares with the Company’s strategic operating plan.

Under the original terms of the award, vesting of the 2014 grant of performance shares is dependent upon NiSource meeting certain performance measures over a three-year performance period and the executive’s continued employment through January 28, 2017. Special vesting rules apply in the event of death, “Retirement,” “Disability” or a “Change-in-Control” (each as defined in the NiSource Omnibus Plan). Termination for any other reason will result in forfeiture of all performance shares. The performance measures on which vesting of the 2014 performance shares is contingent relate to NiSource’s cumulative net operating earnings per share over the three-year period from January 1, 2014 through December 31, 2016 and NiSource’s Relative Total Shareholder Return (“RTSR”). The NiSource ONC Committee approved the application of these measures for the 2014-2016 performance cycle because they were deemed to be important to NiSource’s success in increasing stockholder value. The NiSource ONC Committee determined it appropriate to eliminate funds from operations as a performance measure for the 2014 performance share awards in order to further align the 2014 performance shares with the Company’s strategic operating plan.

NiSource defines RTSR as the annualized growth in the dividends and share price of a share of NiSource’s common stock, calculated using a 20-day trading average of the closing price of NiSource’s common stock, over a period beginning December 31, 2013 and ending on December 31, 2016 compared to the similarly calculated total shareholder return performance of a peer group of energy companies, pre-determined by the NiSource ONC Committee. The peer group of companies selected by the NiSource ONC Committee for the purpose of determining RTSR is broader than the NiSource Comparative Group utilized by the NiSource ONC Committee in its compensation decision-making. The 36 energy companies, including 15 companies from the NiSource Comparative Group, were selected by the NiSource ONC Committee because each of the companies is similarly affected by external factors that impact stock price such as interest rates and industry opportunities and challenges.

Under the original terms of the award, if the pre-established performance goals and service condition are met at target performance levels, award recipients would earn 100% of the target number of performance shares awarded. The NiSource ONC Committee also approved trigger and stretch goals for each measure for each executive. If the trigger level is not met, then the executive would not receive any portion of the grant. If the target level is exceeded, the executive could receive up to a maximum of 200% of the target value of the grant unless total shareholder return is negative for the performance period, in which case, the maximum payout for RTSR would be at target regardless of performance relative to the peer group. When the result of net operating

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earnings per share and RTSR above the 50^th percentile lands between two goals (for example, between the target and stretch goal), then the long-term incentive payout is determined by linear interpolation and is expressed as a percentage of the target opportunity. There is no interpolation between goals below the 50^th percentile for the RTSR metric.

The measures and goals pertaining to the 2014 performance share awards were:


Performance Measure	Weight			Trigger (50% Award)		Target (100% Award)		Stretch (200% Award)
Cumulative Net Operating Earnings Per Share for 2014-2016		50	%	$	5.11	$	5.26	>$	5.63
Relative Total Shareholder Return as of December 31, 2016		50	%		40-49^th Percentile		50^th Percentile		100^th Percentile

The NiSource ONC Committee authorized 2014 performance share awards to the Named Executive Officers in the following amounts:


Named Executive Officer	Number of Performance Shares Awarded
Robert C. Skaggs, Jr.		109,457
Stephen P. Smith		39,405
Glen L. Kettering		14,594
Shawn L. Patterson		6,567
Stanley G. Chapman, III		11,675

2014 Interim Chief Executive Officer Restricted Stock Unit Award. In January 2014, the NiSource ONC Committee granted Mr. Kettering a special award of 14,594 restricted stock units in recognition of his role as interim Group Chief Executive Officer of NiSource CPG. All of these restricted stock units vest three years from the date of grant.

2014 Retention Restricted Stock Unit Awards. The NiSource ONC Committee granted special awards of restricted stock units to Messrs. Patterson and Chapman for retention purposes. Accordingly, in August 2014, Mr. Patterson received a special award of 40,128 restricted stock units and, in March 2014, Mr. Chapman received a special award of 30,000 restricted stock units. These restricted stock units vest in one-third annual increments, subject to Mr. Patterson’s and Mr. Chapman’s continued employment through the applicable vesting dates.

2012 Performance Share Awards. In 2012, the NiSource ONC Committee approved a grant of performance shares to executives within the NiSource organization, including each of the Named Executive Officers. Vesting of the 2012 grant of performance shares was dependent upon NiSource meeting certain performance measures over the three-year period from 2012 through 2014 and the executive’s continued employment through January 30, 2015. The performance measures on which the 2012 performance shares were based related to cumulative net operating earnings per share and cumulative funds from operations over the three-year period from January 1, 2012 through December 31, 2014, and RTSR beginning December 31, 2011 through December 31, 2014. The peer group of companies selected by the NiSource ONC Committee for the purpose of determining RTSR for the 2012 performance share awards was broader than the NiSource Comparative Group. The 36 energy companies, including ten companies from the NiSource Comparative Group at the time, were selected by the NiSource ONC Committee because each of the companies was deemed to be similarly affected by external factors that impact stock price such as interest rates and industry opportunities and challenges. Based on NiSource’s performance as certified by the NiSource ONC Committee in January 2015, 183% of the performance share awards vested as described below.

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The performance measures and their weightings, as certified by the NiSource ONC Committee, were:


Performance Measure⁽¹⁾	Weight			Trigger (50% Award)		Target (100% Award)		Stretch (150% Award)		Actual Results
Cumulative Net Operating Earnings Per Share for 2012-2014		40	%	$	4.41	$	4.56	>$	4.88	$	4.76
Cumulative Funds from Operations for 2012-2014		40	%	$	3,002M	$	3,302M	>$	3,902M	$	3,964M
Relative Total Shareholder Return as of December 31, 2014		20	%		40-49^th Percentile		50^th Percentile		100^th Percentile		95^th Percentile

(1)	When the result for a particular measure lands between two goals (for example, between the target and stretch goal), then the long-term incentive award opportunity is determined by interpolation and is expressed as a percentage of the target opportunity.

Thereafter, each Named Executive Officer fully vested in the performance shares, payable one-for-one in shares of NiSource’s common stock, as set forth in the table below:


Named Executive Officer	2012 Performance Shares
Robert C. Skaggs, Jr.		234,917
Stephen P. Smith		97,881
Glen L. Kettering		39,153
Shawn L. Patterson		15,661
Stanley G. Chapman, III		21,534

Changes to Executive Compensation Program in Connection with Separation

In January 2015, the NiSource ONC Committee determined that the 2015 annual long-term incentive awards to all NiSource executives, including the Named Executive Officers, should be in the form of service-based restricted stock units instead of performance-based shares in light of the proposed Separation. These service-based restricted stock units do not vest until February 2, 2018, at which time they will vest in full subject to the award recipient’s continued service through the vesting date.

We expect that NiSource restricted stock units held by employees of NiSource CPG, including each of the Named Executive Officers, on the date of Separation will convert into CPG restricted stock units in a manner that preserves the value of the award following the Separation and that such CPG restricted stock units will be on substantially the same terms and conditions as the original NiSource restricted stock units, except that the vesting of such CPG restricted stock units will be based solely on continued service with CPG. It is expected that NiSource PSAs that are outstanding on the date of Separation will be adjusted or converted into CPG awards in a manner that preserves the intended value of such awards following the Separation. It is also expected that, subject to any determination by the NiSource ONC Committee with respect to the performance conditions applicable to the NiSource PSAs, the adjusted CPG awards will preserve substantially the same service-vesting conditions as the original NiSource PSAs, except that the vesting of awards held by CPG employees will be based solely on continued service with CPG. The NiSource ONC Committee also intends to make adjustments to the performance conditions and performance period for the 2015 annual performance-based cash incentive awards under the Incentive Plan, contingent upon the occurrence of the Separation.

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Anticipated Compensation Programs Following the Separation

As discussed above, our post-Separation compensation programs will be designed to pay-for-performance and focus on the achievement of specified business objectives. We expect that CPG’s executive compensation program will provide a total compensation package that is competitive with prevailing practices and allows for increased compensation when superior financial performance is achieved, but does not encourage unnecessary and excessive risk taking that could adversely affect CPG and its stockholders.

We anticipate implementing compensation elements and policies that are similar to the compensation elements and policies offered by NiSource. Accordingly, we expect to adopt an annual incentive plan and long-term incentive compensation arrangements that are designed to motivate participants, including the Named Executive Officers, to meet and exceed short and long-term business objectives. In addition, we anticipate adopting severance and change-in-control benefits, pension programs, savings programs, deferred compensation arrangements and health and welfare benefit arrangements that are comparable to the arrangements offered by NiSource. We also expect to implement leading governance practices, including clawback policies, hedging/pledging policies and executive stock ownership guidelines similar to those employed by NiSource, in order to further align our executive compensation program with the interests of CPG and its stockholders.

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COLUMBIA PIPELINE GROUP, INC. 2015 OMNIBUS INCENTIVE PLAN

Prior to the Separation, we expect to adopt the Omnibus Plan which is intended to promote the achievement of both short-term and long-term objectives of CPG by (a) aligning compensation of participants with the interests of CPG stockholders, (b) enhancing the interest of participants in the growth and success of CPG and (c) attracting and retaining participants of outstanding competence. The material terms of the Omnibus Plan are expected to be as follows:

Plan Term

The Omnibus Plan term will begin on the effective date of the Separation. If approved, the Omnibus Plan will remain in effect until all shares of CPG subject to the Omnibus Plan are distributed, or the Omnibus Plan is terminated as described below.

Administration

The Omnibus Plan will be administered by the Human Resources and Compensation Committee of our board of directors, or such other committee as our board of directors appoints from time to time, which will consist of two or more directors, all of whom are intended to satisfy the requirements for an “outside director” under Section 162(m) of the Code, a “non-employee director” within the meaning of Rule 16b-3 of the Exchange Act, and an “independent director” under the NYSE listing standards. The Human Resources and Compensation Committee has the discretion to interpret the Omnibus Plan and any award or other agreement employed by CPG in the administration of the Omnibus Plan. Subject to the provisions of the Omnibus Plan, the Human Resources and Compensation Committee has the power to:

•

determine when and to whom awards will be granted;

•

make awards under the Omnibus Plan;

•

determine the fair market value of shares or other property, where applicable;

•

determine the terms, conditions and restrictions applicable to each award and any shares acquired pursuant to such awards;

•

determine how an award will be settled;

•

approve one or more forms of award agreements;

•

amend, modify, extend, cancel or renew any award or waive any restrictions or conditions applicable to any award or any shares acquired upon the exercise of an award;

•

accelerate, continue, extend or defer the exercisability of any award or the vesting of any shares acquired upon the exercise of an award;

•

prescribe, amend or rescind any rules and regulations relating to the administration of the Omnibus Plan; and

•

make all other determinations necessary or advisable for the administration of the Omnibus Plan.

Notwithstanding the foregoing, our board of directors will perform the functions of the Human Resources and Compensation Committee for purposes of granting awards to non-employee directors.

Eligible Participants

The Omnibus Plan gives the Human Resources and Compensation Committee full discretion to designate any non-employee director of the Company or any employee of the Company or an affiliate as a participant in the Omnibus Plan. In addition, in connection with the Separation, and pursuant to the terms of the Employee Matters

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Agreement, employees and directors of CPG and its subsidiaries will receive awards under the Omnibus Plan that are granted in substitution for awards outstanding under the NiSource equity plans.

Number of Shares and Limitations

The total number of shares of CPG common stock available for distribution under the Omnibus Plan will be 8,000,000. The following shares related to awards will be available for issuance again under the Omnibus Plan:

•

shares related to awards paid in cash, and

•

shares related to awards that expire, are forfeited, are cancelled or terminate for any other reason without the delivery of the shares.

In addition, the following shares related to awards also will be available for issuance again under the Omnibus Plan:

•

shares equal in number to the shares withheld, surrendered or tendered in payment of the exercise price of an award;

•

shares tendered or withheld in order to satisfy tax withholding obligations; and

•

shares reacquired by the Company on the open market or otherwise using cash proceeds from the exercise of awards.

Subject to the adjustment provisions included in the Omnibus Plan, the maximum aggregate face value (fair market value of a share of common stock on the date of grant times the number of awards granted) that may be covered by awards of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards in any one fiscal year to any one participant will be $15,000,000 per year. The maximum aggregate payout (determined as of the end of the applicable performance period) with respect to cash-based awards to any one participant will be $15,000,000 per year.

Types of Awards

The types of awards that may be granted under the Omnibus Plan include incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards.

Subject to certain restrictions applicable to incentive stock options, awards granted under the Omnibus Plan will be exercisable by the participants at such times as are determined by the Human Resources and Compensation Committee, but in no event may the term of an award be longer than ten years after the date of grant. In addition to the general characteristics of all of the awards described above, the basic characteristics of awards that may be granted under the Omnibus Plan are described below.

Incentive and Nonqualified Stock Options (“ISOs” and “NSOs”)

Both incentive and nonqualified stock options may be granted to participants at such exercise prices as the Human Resources and Compensation Committee may determine, but the exercise price for any option may not be less than 100% of the fair market value (as defined in the Omnibus Plan) of a share of CPG common stock as of the date the option is granted. Stock options may be granted and exercised at such times as the Human Resources and Compensation Committee may determine, except that (a) ISOs may be granted only to employees, (b) no ISOs may be granted more than ten years after the effective date of the Omnibus Plan, (c) an option shall not be exercisable more than ten years after the date of grant and (d) the aggregate grant date fair market value of the shares of CPG common stock with respect to which ISOs granted under the Omnibus Plan and any other plan of the Company first become exercisable in any calendar year for any employee may not exceed the $100,000

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maximum amount permitted under Section 422(d) of the Code. Additional restrictions apply to an ISO granted to an individual who beneficially owns more than 10% of the combined voting power of all classes of stock of the Company.

The purchase price payable upon exercise of options generally may be paid in any of the following methods:

•

in cash;

•

by authorizing a third party with which the optionee has a brokerage or similar account to sell the shares (or a sufficient portion of such shares) acquired upon the exercise of the option and remit to CPG a portion of the sale proceeds sufficient to pay the entire option exercise price;

•

by delivering shares that have an aggregate fair market value on the date of exercise equal to the option exercise price;

•

by authorizing CPG to withhold from the total number of shares as to which the option is being exercised the number of shares having a fair market value on the date of exercise equal to the aggregate option exercise price for the total number of shares as to which the option is being exercised;

•

by such other means by which the Human Resources and Compensation Committee determines to be consistent with the purpose of the Omnibus Plan and applicable law; or

•

by any combination of items listed above.

Stock Appreciation Rights (“SARs”)

The value of a SAR granted to a participant is determined by the appreciation in the number of shares of CPG common stock subject to the SAR during its term, subject to any limitations upon the amount or percentage of total appreciation that the Human Resources and Compensation Committee may determine at the time the right is granted. The participant receives all or a portion of the amount by which the fair market value of a specified number of shares, as of the date the SAR is exercised, exceeds a price specified by the Human Resources and Compensation Committee at the time the right is granted. The price specified by the Human Resources and Compensation Committee must be at least 100% of the fair market value of the specified number of shares of CPG common stock to which the right relates, determined as of the date the SAR is granted. A SAR may be granted in connection with a previously or contemporaneously granted option, or independent of any option. A SAR may be paid in cash, shares of CPG common stock or a combination of cash and shares as determined by the Human Resources and Compensation Committee. No SAR may be exercised more than ten years after its date of grant.

Restricted Stock and Restricted Stock Units (“RSUs”)

The Human Resources and Compensation Committee may grant participants awards of restricted stock and RSUs. Restricted stock involves the granting of shares to participants subject to restrictions on transferability and any other restrictions the Human Resources and Compensation Committee may impose. The restrictions lapse if either the holder continues to perform services to CPG or its affiliates for a specified period of time established by the Human Resources and Compensation Committee under the applicable award agreement or satisfies other restrictions, including performance-based restrictions, during the period of time established by the Human Resources and Compensation Committee. RSUs are similar to restricted stock except that no shares actually are awarded to the participant on the date of grant, and the holder typically does not enjoy any stockholder rights with respect to the units. Restricted stock awards are settled in shares. RSU awards may be settled in cash, shares or a combination of cash and shares, as determined by the Human Resources and Compensation Committee and provided in the applicable award agreement.

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Performance Shares

The Human Resources and Compensation Committee may grant participants awards of performance shares. The period of time over which performance targets are measured will be of such duration as the Human Resources and Compensation Committee will determine in an award agreement. Upon satisfaction of the applicable performance targets during the performance period, the participant will be entitled to receive shares of CPG common stock.

Performance Units

The Human Resources and Compensation Committee may grant participants awards of performance units. The period of time over which the performance goals are measured will be no less than two years, unless otherwise determined by the Human Resources and Compensation Committee in an award agreement. Upon satisfaction of the applicable performance targets during the performance period, the participant will be entitled to receive either shares, cash or a combination of shares and cash as determined by the Human Resources and Compensation Committee in an award agreement.

Cash-Based Awards

Cash-based awards entitle the participants to payments of amounts of cash determined by the Human Resources and Compensation Committee based upon the achievement of specified performance targets during a specified performance period, which typically will be one year unless otherwise determined by the Human Resources and Compensation Committee. Each cash-based award will have its value determined by the Human Resources and Compensation Committee.

Other Stock-Based Awards

The Human Resources and Compensation Committee may also grant other awards that are valued in whole or in part by reference to, or are otherwise based on and/or payable in, shares of CPG common stock. Other stock-based awards are a catch-all category to provide for awards of stock-based compensation that do not fit within the scope of the other specifically described types of awards. Payments with respect to other stock-based awards may be made in cash, shares or a combination of cash and shares as determined by the Human Resources and Compensation Committee. The Human Resources and Compensation Committee has the discretion to determine the terms and conditions of these other stock-based awards.

Performance Targets

Awards under the Omnibus Plan may be conditioned upon the attainment of performance targets. Awards may be based on any number and type of performance targets that the Human Resources and Compensation Committee determines are desirable. In setting performance targets, the Human Resources and Compensation Committee may assign payout percentages to various levels of performance that will be applied to reduce or increase the payout connected to the award when performance over a performance period either falls short of or exceeds the performance target.

The performance targets established by the Human Resources and Compensation Committee may relate to corporate, division, department or business unit performance and may be established in terms of any one or a combination of the following performance measures: revenue and income measures (which include growth in gross revenue, net income, earnings per share, specified revenue targets, ratio of earnings to stockholders’ equity or to total assets, pre-tax income, earnings before interest and taxes and earnings before interest, taxes, depreciation, amortization, distributable cash flow, and depletion); return measures (which include dividend payments, total stockholders’ return, return on capital or return on investment, return on assets, return on net assets and return on equity); expense and efficiency measures (which include expense control, productivity and

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gross margins); operating measures (which include operating earnings per share, business unit operating earnings, operating income, operating margins, funds from operations and cash from operations); leverage measures (which include total debt or change in total debt or the rating on the Company’s debt as determined by external rating agencies); specified customer satisfaction targets; specified safety targets (which include environmental performance); specified diversity targets; specified reliability targets; satisfactory completion of a major project or organizational initiative with specific criteria set in advance by the Human Resources and Compensation Committee defining “satisfactory;” and achievement of balance sheet, income statement or cash flow statement objectives.

Duration, Adjustments, Modifications, Terminations

The Omnibus Plan will remain in effect until all shares of CPG subject to the Omnibus Plan are distributed, or the Omnibus Plan is terminated as described below.

In the event of a recapitalization, stock split, reverse stock split, spin-off, spin-out or other distribution of assets to stockholders, stock distributions or combinations of shares, payment of stock dividends, other increase or decrease in the number of such shares outstanding effected without receipt of consideration by CPG or any other occurrence for which the Human Resources and Compensation Committee determines an adjustment is appropriate, the Human Resources and Compensation Committee will equitably adjust the number and type of shares available for awards or the number and type of shares and amount of cash subject to outstanding awards, the option exercise price of outstanding options, and provisions regarding payment with respect to outstanding awards. The Human Resources and Compensation Committee has the discretion to make similar adjustments in connection with other changes in CPG’s capitalization, including due to a merger, reorganization or consolidation.

The Omnibus Plan also gives our board of directors and the Human Resources and Compensation Committee the right to terminate, suspend or amend the Omnibus Plan without the authorization of stockholders to the extent allowed by law, including without limitation any rules issued by the SEC under Section 16 of the Exchange Act, insofar as stockholder approval thereof is required in order for the Omnibus Plan to continue to satisfy the requirements of Rule 16b-3 of the Exchange Act or the rules of any applicable stock exchange. No termination, suspension or amendment of the Omnibus Plan will adversely affect any right acquired by any participant under an award granted before the date of such termination, suspension or amendment, unless such participant consents; but it will be conclusively presumed that any adjustment for changes in capitalization as provided for in the Omnibus Plan does not adversely affect any such right.

Upon a change in control, all outstanding awards will become fully exercisable and all restrictions on the awards will terminate; provided, however, that the Human Resources and Compensation Committee may determine and provide through an award agreement or other means the extent of vesting and the treatment of partially completed performance periods (if any) for any awards outstanding upon a change in control. Further, the Human Resources and Compensation Committee, as constituted before such change in control, is authorized, and has sole discretion, as to any award, either at the time such award is granted or any time thereafter, to take any one or more of the following actions:

•

provide for the cancellation of any such award for an amount of cash equal to the difference between the exercise price and the then fair market value of the shares covered thereby had such award been currently exercisable;

•

make such adjustment to any such award then outstanding as the Human Resources and Compensation Committee deems appropriate to reflect such change in control; or

•

cause any such award then outstanding to be assumed, by the acquiring or surviving corporation, after such change in control.

New Plan Benefits

The benefits that might be received by officers, employees and nonemployee directors cannot be determined at this time. All officers, employees and nonemployee directors are eligible for consideration to participate in the Omnibus Plan.

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COMPENSATION OF EXECUTIVE OFFICERS

Summary. The following table summarizes compensation for services to NiSource and its affiliates for 2014 awarded to, earned by or paid to each of the Named Executive Officers as of December 31, 2014.

2014 Summary Compensation Table


Name and Principal Position	Year		Salary ($)⁽¹⁾		Bonus ($)⁽²⁾		Stock Awards ($)⁽³⁾		Non-Equity Incentive Plan Compensation ($)⁽⁴⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽⁵⁾		All Other Compensation ($)⁽⁶⁾		Total ($)⁽⁶⁾
Robert C. Skaggs, Jr.		2014		946,667		1,785,000		3,395,356		1,715,000		357,545		82,471		8,282,039
President and Chief Executive Officer of NiSource		2013		900,000		—		2,662,652		1,224,000		306,743		85,625		5,179,020
		2012		900,000		—		2,635,436		720,000		347,464		79,336		4,682,236

Stephen P. Smith		2014		589,583		750,000		1,222,343		579,600		80,415		52,993		3,274,934
Executive Vice President and Chief Financial Officer of NiSource		2013		575,000		—		1,109,438		539,350		70,691		52,436		2,346,915
		2012		564,583		—		1,098,088		438,725		70,947		54,601		2,226,944

Glen L. Kettering		2014		448,333		600,000		908,914		426,000		109,019		299,848		2,792,114
Executive Vice President and Group Chief Executive Officer of NiSource CPG		2013		340,000		500,000		443,775		275,400		120,229		68,226		1,747,630
		2012		340,000		—		439,239		222,360		82,106		71,750		1,155,455

Shawn L. Patterson		2014		350,417		200,000		1,521,378		247,044		43,639		38,457		2,400,935
President of Operations and Project Delivery of NiSource CPG
Stanley G. Chapman, III		2014		386,667		210,000		1,299,159		272,600		—		29,273		2,197,699
Executive Vice President and Chief Commercial Officer for various CEG subsidiaries

(1)	Salary deferred at the election of the Named Executive Officer is reported in the category and year in which such salary was earned.

(2)

This column shows retention bonuses of $100,000 paid to each of Messrs. Patterson and Chapman as well as discretionary bonus payouts to each Named Executive Officer that are in addition to any amounts paid under the Incentive Plan described in footnote 4. These bonus amounts are more fully described in the “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—Additional Discretionary Lump Sum Payouts to the Named Executive Officers Based on 2014 Performance.”

(3)

For a discussion of stock awards granted in 2014, see “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—LTIP Awards” and the 2014 Grants of Plan-Based Awards table. This column shows the aggregate grant date fair value, computed in accordance with Financial Accounting Standards Board (“FASB”) ASC Topic 718, of the restricted stock, restricted stock units and performance shares granted in 2014 based on the average price of NiSource common stock on the NYSE at the grant date, discounted for the value of dividends not received in the vesting period. Since the performance share awards are subject to performance conditions, the grant date value is based upon the probable outcome of such conditions. The following table shows the value of the performance share awards reported in the Summary Compensation Table at the grant date assuming that the highest level of performance conditions will be achieved.


Name	Maximum Performance Share Potential as of Grant Date for Awards ($)
Robert C. Skaggs, Jr.		6,790,712
Stephen P. Smith		2,444,686
Glen L. Kettering		905,412
Shawn L. Patterson		407,417
Stanley G. Chapman, III		724,317

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(4)

For 2014, the Incentive Plan payout amount for each of the Named Executive Officers reflected above in the column entitled Non-Equity Incentive Plan Compensation was based upon overall corporate and business unit performance. For more information regarding 2014 corporate and business unit performance, Incentive Plan payout opportunities for the Named Executive Officers and the actual payout amounts, see “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—Annual Performance-Based Cash Incentives” and “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—2014 Incentive Plan Payouts to the Named Executive Officers.”

(5)

This column shows the change in the present value of each pension eligible Named Executive Officer’s accumulated benefits under NiSource’s tax-qualified pension plans and the non-qualified Pension Restoration Plan as a result of annual pay and interest credits to their account balance under the plans as described in the narrative to the 2014 Pension Benefits table. Because he was hired after January 1, 2010, Mr. Chapman is not eligible to participate in either of NiSource’s pension plans. For a description of these plans and the basis used to develop the present values, see the 2014 Pension Benefits table and accompanying narrative. No earnings on deferred compensation are shown in this column, since no earnings were above market or preferential.

(6)	The table below provides a breakdown of the amounts shown in the “All Other Compensation” column for each Named Executive Officer in 2014.


	Perquisites & Personal Benefits (a) ($)		Other Compensation
Name	Perquisites & Personal Benefits (a) ($)		Company Contributions to 401(k) Plan (b) ($)		Company Contributions to Savings Restoration Plan (c) ($)		Total ($)
Robert C. Skaggs, Jr.		11,471		19,500		51,500		82,471
Stephen P. Smith		8,774		19,500		24,719		52,993
Glen L. Kettering		257,973		19,500		22,375		299,848
Shawn L. Patterson		12,176		19,500		6,781		38,457
Stanley G. Chapman, III		273		19,500		9,500		29,273

(a)

All perquisites are valued based on the aggregate incremental cost to NiSource, as required by the rules of the SEC. The “Compensation Discussion and Analysis—Other Compensation and Benefits—Perquisites” section contains additional information about the perquisites provided by NiSource to its executive officers. The perquisite amounts listed include financial planning and tax services as follows: Mr. Skaggs, $11,471; Mr. Smith, $8,774; Mr. Kettering, $9,870; and Mr. Patterson, $12,015; travel expense as follows: Mr. Kettering, $233,579; living expense as follows: Mr. Kettering, $14,155; spousal travel as follows: Mr. Kettering, $369; and taxable gifts as follows: Mr. Patterson, $161; and Mr. Chapman, $273. The travel expense for Mr. Kettering was calculated by NiSource based on the incremental variable operating costs associated with the use of the NiSource-leased aircraft to commute to the executive’s office, which includes an hourly use rate, fuel rate and other flight related fees and expenses. Executives are responsible for all taxes associated with the use of NiSource’s aircraft for this purpose.

(b)

This column reflects NiSource matching contributions and profit sharing contributions made on behalf of each of the Named Executive Officers. The 401(k) Plan is a tax-qualified defined contribution plan, as described above under “Compensation Discussion and Analysis—Other Compensation and Benefits—Savings Programs.”

(c)

This column reflects NiSource matching contributions and profit sharing contributions made on behalf of the Named Executive Officers. The Savings Restoration Plan is a non-qualified defined contribution plan, as described above under “Compensation Discussion and Analysis—Other Compensation and Benefits—Savings Programs,” and in the narrative following the Non-qualified Deferred Compensation table.

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2014 Grants of Plan-Based Awards

The following table sets forth information concerning plan-based awards under the NiSource Omnibus Plan to the Named Executive Officers in 2014.


			Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾						Estimated Future Payouts Under Equity Incentive Plan Awards⁽²⁾						All Other Stock Awards Number of Shares of Stock or Units (#)⁽³⁾		Grant Date Fair Value of Stock and Option Awards ($)⁽⁴⁾
Name	Grant Date		Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)				Grant Date Fair Value of Stock and Option Awards ($)⁽⁴⁾
Robert C. Skaggs, Jr.		—		490,000		1,225,000		1,960,000		—		—		—		—		—
		01/30/2014		—		—		—		54,729		109,457		218,914		—		3,395,356
Stephen P. Smith		—		180,000		420,000		660,000		—		—		—		—		—
		01/30/2014		—		—		—		19,703		39,405		78,810		—		1,222,343
Glen L. Kettering		—		125,000		300,000		475,000		—		—		—		—		—
		01/30/2014		—		—		—		7,297		14,594		29,188		—		452,706
		01/30/2014		—		—		—		—		—		—		14,594		456,208
Shawn L. Patterson		—		90,000		180,000		270,000		—		—		—		—		—
		01/30/2014		—		—		—		3,284		6,567		13,134		—		203,708
		08/04/2014		—		—		—		—		—		—		40,128		1,317,670
Stanley G. Chapman, III		—		98,750		197,500		296,250		—		—		—		—		—
		01/30/2014		—		—		—		5,838		11,675		23,350		—		362,159
		03/24/2014		—		—		—		—		—		—		30,000		937,000

(1)

The information in the “Threshold,” “Target,” and “Maximum” columns reflects potential payouts based on the performance targets set under the 2014 Incentive Plan, as described above in the section entitled “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—Annual Performance-Based Cash Incentives.” The amounts actually paid under the 2014 Incentive Plan were based on 2014 performance and appear in the “Non-Equity Incentive Plan Compensation” column of the 2014 Summary Compensation Table. For a description of the 2014 Incentive Plan payout amounts, please see the section entitled “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—Annual Performance-Based Cash Incentives.”

(2)

The information in the “Threshold,” “Target,” and “Maximum” columns reflects the potential share payouts under the 2014 NiSource performance share awards. Under the original terms of the awards, the actual number of performance shares earned is determined based on NiSource performance over the three-year period from 2014 through 2016. In order for a participant to receive shares, NiSource must attain specific performance goals and the participant must satisfy the applicable service condition. For a description, please see the section entitled “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—LTIP Awards.” If the target level of performance is met, the individual would receive 100% of the grant designated by the NiSource ONC Committee. The NiSource ONC Committee also set threshold and maximum goals. If the threshold level is not met, then the executive would not receive any value of that portion of the grant. At the threshold level the executive would receive 50% of the value of the target value of the grant, and at the maximum level the executive would receive 200% of the target value of the grant.

(3)

The information in this column reflects time-based restricted stock units granted to Messrs. Kettering, Patterson and Chapman. Mr. Kettering’s grant will vest in its entirety on January 30, 2017, Mr. Patterson’s grant will vest in one-third increments on August 4, 2017, August 4, 2018 and August 4, 2019, and Mr. Chapman’s grant will vest in one-third increments on March 24, 2017, March 24, 2018 and March 24, 2019, in each case, subject to the continued employment of the executive on the applicable vesting date.

(4)

This column shows the aggregate grant date fair value, computed in accordance with FASB ASC Topic 718, of the restricted stock units and performance shares granted in 2014 based on the average price of NiSource common stock on the NYSE on the grant date, discounted for the value of dividends not received in the vesting period. Since the performance share awards are subject to performance conditions, the grant date value is based upon the probable outcome of such conditions.

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2014 Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information at fiscal year-end concerning outstanding grants of equity awards to the Named Executive Officers, including awards of options to purchase NiSource common stock, restricted stock, restricted stock units, contingent stock and performance shares to the Named Executive Officers. No options were granted in 2014.


	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options Exercisable (#)⁽¹⁾		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)			Market Value of Shares or Units of Stock That Have Not Vested ($)⁽²⁾		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)			Equity Incentive Plan Awards Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)⁽³⁾
Robert C. Skaggs, Jr.		—		—		—		64,043	⁽⁴⁾		2,716,704		—			—
		—		—		—		46,685	⁽⁵⁾		1,980,378		—			—
		—		—		—		29,126	⁽⁶⁾		1,235,525		—			—
		—		—		—		234,917	⁽⁷⁾		9,965,179		—			—
		—		—		—		—			—		113,208	⁽⁸⁾		4,802,283
		—		—		—		—			—		109,457	⁽⁹⁾		4,643,166
Stephen P. Smith		—		—		—		97,881	⁽⁷⁾		4,152,112		—			—
		—		—		—		—			—		47,170	⁽⁸⁾		2,000,951
		—		—		—		—			—		39,405	⁽⁹⁾		1,671,560
Glen L. Kettering		—		—		—		39,153	⁽⁷⁾		1,660,870		—			—
		—		—		—		—			—		18,868	⁽⁸⁾		800,381
		—		—		—		—			—		14,594	⁽⁹⁾		619,077
		—		—		—		14,594	⁽¹⁰⁾		619,077		—			—
Shawn L. Patterson		—		—		—		15,661	⁽⁷⁾		664,340		—			—
								20,644	⁽¹¹⁾		875,718		—			—
		—		—		—		—			—		7,547	⁽⁸⁾		320,144
		—		—		—		—			—		6,567	⁽⁹⁾		278,572
		—		—		—		40,128	⁽¹²⁾		1,702,230		—			—
Stanley G. Chapman, III		—		—		—		21,534	⁽⁷⁾		913,472		—			—
		—		—		—		—			—		10,377	⁽⁸⁾		440,192
		—		—		—		17,188	⁽¹³⁾		729,115		—			—
		—		—		—		—			—		11,675	⁽⁹⁾		495,254
		—		—		—		30,000	⁽¹⁴⁾		1,272,600		—			—

(1)	There are no outstanding options held by the Named Executive Officers.

(2)	This column shows the market value of the unvested restricted stock units and restricted stock awards held by the Named Executive Officers, based on $42.42 per share, the closing price of NiSource common stock on the NYSE on December 31, 2014.

(3)	This column shows the market value of the unvested performance shares held by the Named Executive Officers payable at target levels, based on $42.42 per share, the closing price of NiSource common stock on the NYSE on December 31, 2014.

(4)

The award shown represents restricted stock units granted on March 24, 2009. Vesting of these restricted stock units has been delayed in accordance with the terms of Mr. Skaggs’ award agreement due to limitations on deductibility under Section 162(m) of the Code. These units will vest and be payable in shares of NiSource common stock on the earlier to occur of: his termination of employment, the date he is no longer subject to Section 162(m) of the Code or the date that such shares could be paid to him and be deductible under Section 162(m) of the Code.

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(5)

The award shown represents restricted stock units granted on January 22, 2010. Vesting of these restricted stock units has been delayed in accordance with the terms of Mr. Skaggs’ award agreement due to limitations on deductibility under Section 162(m) of the Code. These units will vest and be payable in shares of NiSource common stock on the earlier to occur of: his termination of employment, the date he is no longer subject to Section 162(m) of the Code or the date that the restricted stock units can be paid to him and be deductible under Section 162(m) of the Code.

(6)

The award shown represents restricted stock units granted on March 23, 2010. Vesting of these restricted stock units has been delayed in accordance with the terms of Mr. Skaggs’ award agreement due to limitations on deductibility under Section 162(m) of the Code. These units will vest and be payable in shares of NiSource common stock on the earlier to occur of: his termination of employment, the date he is no longer subject to Section 162(m) of the Code or the date that the restricted stock units can be paid to him and be deductible under Section 162(m) of the Code.

(7)

The awards shown represent performance shares granted January 26, 2012. These awards vested on February 18, 2015, immediately following the certification of NiSource performance after satisfaction of the service condition on January 30, 2015. The performance measures, their weightings and results are set forth in the Section entitled “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—LTIP Awards.”

(8)

The awards shown represent performance shares granted on January 24, 2013 at target levels. The number of shares that will actually vest is dependent upon NiSource meeting multi-year performance measures over the 2013-2015 performance period and the executive’s continued employment through February 29, 2016.

(9)

The awards shown represent performance shares granted on January 30, 2014 at target levels. The number of shares that will actually vest is dependent upon NiSource meeting multi-year performance measures over the 2014-2016 performance period and the executive’s continued employment through February 28, 2017. For a description of the performance share awards and the performance criteria and vesting schedule, please see the Section entitled “Compensation Discussion and Analysis—Actions Related to 2014 Compensation—LTIP Awards.”

(10)	The award shown represents restricted stock units granted on January 30, 2014. The award vests on January 30, 2017.

(11)	The award shown represents restricted stock units granted on March 26, 2012. The award vests in one-third increments; 6,881 units on March 26, 2015; 6,881 units on March 26, 2016 and 6,882 units on March 26, 2017.

(12)	The award shown represents restricted stock units granted on August 4, 2014. The award vests in one-third increments; 13,376 units on August 4, 2017; 13,376 units on August 4, 2018 and 13,376 units on August 4, 2019.

(13)	The award shown represents restricted stock units granted on May 14, 2013. The award vests in one-third increments: 5,729 units on May 14, 2016; 5,729 units on May 14, 2017 and 5,736 units on May 14, 2018.

(14)	The award shown represents restricted stock units granted on March 24, 2014. The award vests in one-third increments; 10,000 units on March 24, 2017; 10,000 units on March 24, 2018 and 10,000 units on March 24, 2019.

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2014 Option Exercises and Stock Vested


	Option Awards				Stock Awards
Name	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)⁽¹⁾		Number of Shares Acquired on Vesting (#)			Value Realized on Vesting ($)⁽⁵⁾
Robert C. Skaggs, Jr.		—		—		33,476	⁽²⁾		1,144,210
		—		—		150,643	⁽³⁾		5,317,698
Stephen P. Smith		—		—		57,245	⁽³⁾		2,020,749
Glen L. Kettering		—		—		27,116	⁽³⁾		957,195
Shawn L. Patterson		5,000		176,465		6,266	⁽³⁾		221,190
		—		—		1,393	⁽⁴⁾		47,613
Stanley G. Chapman, III		—		—		—			—

(1)	The amounts in this column reflect the value realized upon exercise by the Named Executive Officer which is computed by determining the difference between the market price of the underlying securities at exercise and the exercise price.

(2)	Mr. Skaggs’ restricted stock award vested in its entirety on January 28, 2014. Mr. Skaggs had made an election under section 83(b) of the Code on the grant date and consequently no shares were subject to delayed vesting due to limitations on deductibility under section 162(m) of the Code.

(3)	The awards shown represent performance shares granted on January 28, 2011 that vested on February 18, 2014, immediately following the certification of NiSource performance after satisfaction of the service condition on January 28, 2014.

(4)	Award shown represents restricted stock granted on January 28, 2011, of which 1,393 units vested on February 28, 2014.

(5)	The amounts in this column reflect the value realized by the Named Executive Officer upon the vesting of stock which is computed by multiplying the number of shares by the market value of NiSource common stock on the vesting date.

2014 Pension Benefits


Name	Plan Name	Number of Years of Credited Service (#)		Present Value of Accumulated Benefit ($)
Robert C. Skaggs, Jr.	Columbia Energy Group Pension Plan Pension Restoration Plan		33.5 33.5		1,471,116 4,040,992
Stephen P. Smith	Columbia Energy Group Pension Plan Pension Restoration Plan		6.6 6.6		109,705 302,311
Glen L. Kettering	Columbia Energy Group Pension Plan Pension Restoration Plan		35.5 35.5		838,927 551,140
Shawn L. Patterson	NiSource Inc. Pension Plan Pension Restoration Plan		19.6 19.6		235,458 73,139
Stanley G. Chapman, III⁽¹⁾	—		—		—

(1)	Mr. Chapman is not eligible to participate in any defined benefit pension plan sponsored by NiSource or its affiliates because he was hired after January 1, 2010.

Tax Qualified Pension Plans. NiSource and its affiliates sponsor several qualified defined benefit pension plans for their respective exempt salaried employees hired before January 1, 2010, including the Named Executive Officers identified in the Pension Benefits table. Benefits under these plans are funded through and are payable out of a trust fund, which consists of contributions made by NiSource and the earnings of the fund.

137

The specific defined benefit pension plan in which an employee participates depends upon the affiliate into which the employee was hired. Messrs. Skaggs and Kettering participate in the Columbia Energy Group Pension Plan (the “CEG Plan”) because they were participants in this plan at the time of the acquisition of CEG by NiSource. Mr. Patterson participates in the NiSource Inc. Pension Plan (the “NiSource Plan”) because he was hired into NiSource Corporate Services. Mr. Smith participates in the CEG Plan because he was hired into CEG. Both the CEG Plan and the NiSource Plan previously provided for a “final average pay” benefit (“FAP benefit”) for exempt employees and, alternatively, a cash balance benefit feature (described below). As of January 1, 2011, all active exempt employees participating in NiSource’s qualified defined benefit pension plans, including the CEG Plan and the NiSource Plan, who had accrued a benefit under a FAP benefit formula or, alternatively, under the prior cash balance formula, were converted to each plan’s respective current cash balance formula. Mr. Skaggs was the only Named Executive Officer participating in the FAP benefit at the time of the January 1, 2011 conversion. Mr. Kettering also previously participated in the FAP benefit but was converted to the prior cash balance formula during an earlier choice program. As such, both Messrs. Skaggs’ and Kettering’s accrued benefit under the CEG plan is equal to his respective cash balance account, calculated as described below, or, if greater at the time of retirement, his respective “protected benefit” which is a calculation taking into consideration the accrued benefit under the FAP benefit formula as of the day immediately preceding conversion of the participant’s benefit to the cash balance formula (using only service and compensation earned prior to the benefit conversion). Mr. Smith was participating in the applicable current cash balance benefit formula at the time of the above-referenced conversion.

Pursuant to the above-described conversion of all exempt employees of NiSource, including Mr. Skaggs, to the applicable current cash balance feature, each eligible exempt employee who transitioned to the current cash balance feature has an account benefit consisting of: (1) an “opening account balance” equal to either (a) in the case of an exempt employee transitioning from a FAP benefit formula, the lump sum actuarial equivalent of his accrued FAP benefit as of December 31, 2010, or (b) in the case of an exempt employee transitioning from the prior cash balance formula, equal to the account balance in such prior cash balance formula as of December 31, 2010; plus (2) annual pay and interest credits to the cash balance account. Annual pay credits to a participant’s account under the current cash balance formula equal a percentage of compensation, taking into account the Social Security Taxable Wage Base, based on the participant’s combined age and service for the plan year. The applicable pay credits are listed in the following table:


Sum of Age Plus Years of Service	Percentage of Total Compensation	Percentage of Compensation Above ¹⁄₂ of the Taxable Wage Base
Less than 50	4.0%	1.0%
50-69	5.0%	1.0%
70 or more	6.0%	1.0%

Compensation for purposes of annual pay credits means base pay, any performance-based pay, any “banked” vacation (in the year of vacation payout) and any salary reduction contributions made for the employee pursuant to a plan maintained by NiSource or an affiliate under Sections 125 or 401(k) of the Code, but excluding any amounts deferred to a non-qualified plan maintained by NiSource. In accordance with limits of the Code, the maximum compensation taken into account in determining benefits under the plans with respect to all participants, including the Named Executive Officers, in 2014 was limited to $260,000. Interest is credited each year to the account based on the interest rate on 30-year Treasury securities, as determined by the Internal Revenue Service, for the September immediately preceding the first day of each year, subject to a minimum interest credit of 4%.

The automatic form of benefit under the cash balance features of both the CEG Plan and the NiSource Plan is a single life annuity in the case of an unmarried participant and a 50% joint and survivor pop-up annuity in the case of a married participant (unreduced for the value of the pop-up feature). Optional forms of payment are available under the pension plans, depending on the participant’s marital status and benefit feature. Each optional form of benefit is defined in the applicable plan to be the actuarial equivalent of the normal form of benefit defined in the plan.

138

Under the cash balance features of the applicable plans, any participant may take a distribution of his or her vested cash balance account benefit upon termination of employment, without any reduction. Alternatively, if the participant’s accrued benefit is determined by the protected benefit calculation referenced above ( i.e., the protected benefit calculation is greater than the participant’s cash balance account), the participant would receive the protected benefit amount (which may reflect an actuarial or early retirement reduction if the participant elects to receive it prior to normal retirement date as provided in the applicable plan). Because each of the Named Executive Officers now participates in the current cash balance feature of the applicable plan, each such Named Executive Officer is eligible to take an unreduced distribution of his cash balance account upon termination of employment regardless of age and service, or if greater, the Named Executive Officer could take a distribution of the accrued benefit using the protected benefit calculation. Currently, Mr. Skaggs and Mr. Kettering are the only Named Executive Officers who are eligible for early retirement (which impacts the protected benefit calculation), with early retirement defined under the CEG Plan as the earlier of age 55 with 10 years of eligible service or age 60 with 5 years of eligible service.

Assumptions. The present value of the accumulated benefit for each Named Executive Officer identified above is his account balance payable under the applicable plan. For Mr. Skaggs and Mr. Kettering, this value is greater than the present value of their protected benefit using the assumptions set forth in Note 11—Pension and Other Postretirement Benefits in the Notes to the Consolidated and Combined Financial Statements for Columbia Pipeline Group, Inc. included with this Information Statement. NiSource has not granted any extra years of credited service under the plans identified above.

Non-qualified Pension Benefit Plan. NiSource also sponsors the Pension Restoration Plan. The Pension Restoration Plan is a non-qualified, unfunded defined benefit plan. The plan includes employees of NiSource and its affiliates whose benefits under the applicable tax-qualified pension plan are limited by Sections 415 and 401(a)(17) of the Code including each of the Named Executive Officers. The Pension Restoration Plan provides for a supplemental retirement benefit equal to the difference between (i) the benefit a participant would have received under the qualified pension plan had such benefit not been limited by Sections 415 and 401(a)(17) of the Code, or any other applicable Section, and reduced by deferrals into NiSource’s Deferred Compensation Plan, minus (ii) the actual benefit received under the qualified pension plan after applying any limits and considering deferrals into NiSource’s Deferred Compensation Plan. Participants are provided the opportunity to elect any form of payment available under the qualified pension plan prior to accruing a benefit under the plan. If no election is made, the benefit is payable as a lump sum. The timing of payment under the Pension Restoration Plan generally is 45 days after one of the following: (1) if the participant qualifies for early retirement under the applicable qualified pension plan, following separation from service; or (2) if the participant does not qualify for early retirement at the time of separation from service, the later of separation from service or age 65. Key employees for purposes of Section 409A of the Code, however, may not receive payments triggered by separation from service until 6 months after the termination date.

No plan benefits were paid to any Named Executive Officer under the CEG Plan, the NiSource Plan or the Pension Restoration Plan in 2014.

139

2014 Non-qualified Deferred Compensation


Name	Plan Name	Executive Contributions in Last FY ($)⁽¹⁾		Registrant Contributions in Last FY ($)⁽⁵⁾		Aggregate Earnings in Last FY ($)⁽⁶⁾		Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last FYE ($)⁽⁷⁾
Robert C. Skaggs, Jr.	Deferred Compensation Plan⁽²⁾		—		—		246,016		—		3,540,023
	Savings Restoration Plan⁽³⁾		—		57,442		57,887		—		1,846,013
	Phantom Stock Units⁽⁴⁾		—		—		1,711,449		—		6,932,745
Stephen P. Smith	Savings Restoration Plan⁽³⁾		—		22,400		41,327		—		338,326
Glen L. Kettering	Savings Restoration Plan⁽³⁾		—		5,950		96,810		—		1,075,471
	Phantom Stock Units⁽⁴⁾		—		—		467,206		45,128		1,876,788
Shawn L. Patterson	Savings Restoration Plan⁽³⁾		—		5,203		261		—		8,810
Stanley G. Chapman, III	Savings Restoration Plan⁽³⁾		—		4,892		296		—		9,902

(1)

Amounts shown as “Executive Contributions in Last FY,” if any, were deferred under the Deferred Compensation Plan. The Named Executive Officers may elect to defer and invest between 5% and 80% of their base compensation and between 5% and 100% of their non-equity incentive compensation on a pre-tax basis. These contributions are fully vested.

(2)	For a description of the Deferred Compensation Plan, please see “Compensation Discussion and Analysis—Other Compensation and Benefits—Deferred Compensation Plan” and the narrative accompanying this table.

(3)	For a description of the Savings Restoration Plan, please see “Compensation Discussion and Analysis—Other Compensation and Benefits —Savings Programs” and the narrative accompanying this table. These contributions are fully vested.

(4)

For a description of the phantom stock units, see the narrative accompanying this table. All phantom stock units are vested. Dividend equivalent rights payable with respect to the phantom units are reinvested as additional phantom units at the election of Mr. Skaggs and are paid in cash at the election of Mr. Kettering. Dividend equivalent rights are shown in the aggregate earnings in last fiscal year column and when taken in cash are also shown as a distribution.

(5)	The amount of NiSource contributions for each Named Executive Officer in this column is included in each Named Executive Officer’s compensation reported on the Summary Compensation Table as All Other Compensation.

(6)	The aggregate earnings in this column are not reported in the Summary Compensation Table. For a discussion of investment options under these plans, see the narrative accompanying this table.

(7)

The aggregate balance at December 31, 2014, except the phantom stock units and the aggregate earnings on deferred compensation, reflects amounts for each Named Executive Officer that would have been previously reported as compensation in the Summary Compensation Table for prior years had he been a Named Executive Officer in those prior years.

NiSource sponsors two non-qualified defined contribution plans, neither of which credits above-market or preferential earnings. They are the Savings Restoration Plan and the Deferred Compensation Plan. Participants in both plans have an unsecured contractual right to be paid the amounts due under the plans from NiSource’s general assets.

Savings Restoration Plan. NiSource sponsors the Savings Restoration Plan to provide a supplemental benefit to eligible employees, including the Named Executive Officers, equal to the difference between: (i) the employer contributions (including matching and profit sharing contributions) an employee would have received under the 401(k) Plan had such benefit not been limited by Sections 415 (a limitation on annual contributions under a defined contribution plan of $52,000 for 2014) and 401(a)(17) (a limitation on annual compensation of $260,000 for 2014) of the Code, and the 401(k) Plan’s definition of compensation, which excludes deferrals into the Deferred Compensation Plan for purposes of calculating certain employer contributions, minus (ii) the actual employer contributions the employee received under the 401(k) Plan. Amounts credited under the Savings Restoration Plan are deferred on a pre-tax basis. All of the Named Executive Officers are eligible to participate in the Savings Restoration Plan. Participants’ accounts under the Savings Restoration Plan are 100% vested. Employees designate how these contributions will be invested; the investment options generally are the same as those available under the 401(k) Plan.

140

The timing of payment under the Savings Restoration Plan differs depending on whether the amounts were earned and vested before January 1, 2005 (“Pre-409A Amounts”) or after December 31, 2004 (“Post-409A Amounts”). Pre-409A Amounts generally are payable at the time when amounts under the 401(k) Plan are paid. Participants may elect in any year to withdraw Pre-409A Amounts, but that withdrawal is subject to a 10% reduction to the extent the payment is before the amount was otherwise payable under the 401(k) Plan. Post-409A Amounts generally are paid within 45 days after separation from service, although key employees generally must not be paid until 6 months after their separation date. Participants may not elect to receive early in-service distributions of Post-409A amounts. Both Pre-409A and Post-409A Amounts may be distributed upon an unforeseeable emergency. The form of payment for both amounts is the form elected by the participant among the choices available under the 401(k) Plan.

Deferred Compensation Plan. NiSource sponsors the Deferred Compensation Plan in which employees at certain job levels and other key employees designated by the NiSource ONC Committee, including the Named Executive Officers, are eligible to participate to allow deferral on a pre-tax basis of compensation, including compensation that would otherwise be limited by the Code. Participants may elect to defer and invest between 5% and 80% of their base compensation and between 5% and 80% of their non-equity incentive payment on a pre-tax basis. Employees designate how their contributions will be invested; the investment options generally are the same as those available under the 401(k) Plan. Employee contributions and any earnings thereon are 100% vested. The timing of payment under the Deferred Compensation Plan generally is the March 31 after the date of the participant’s separation from service. This timing applies both to the Pre-409A and Post-409A Amounts. In the case of Post-409A Amounts payable to key employees within the meaning of Section 409A of the Code, payments generally will not be payable until 6 months after the date of separation from service. Participants also may elect to receive in-service distributions of both Pre-409A and Post-409A Amounts. If a participant requests an in-service distribution of a Pre-409A Amount with less than 12 months’ advance notice, however, the distribution is subject to a 10% reduction. Participants may delay the commencement of distributions for five years after their originally scheduled payment date, in accordance with the deferral timing procedures under Section 409A of the Code. Both Pre-409A and Post-409A Amounts also may be paid upon an unforeseeable emergency. The form of payment for both amounts may be either a lump sum or annual installments of up to 15 years, as elected by the participant.

Phantom Units. Messrs. Skaggs and Kettering were granted fully vested phantom stock units following the acquisition by NiSource of CEG, as part of an agreement entered into as of February 1, 2001. Under this agreement, Messrs. Skaggs and Kettering agreed to terminate their rights under a Columbia Energy Group Change-in-Control Agreement. In exchange, they accepted employment with NiSource and agreed to non-competition and non-solicitation provisions. These phantom stock units are recorded as a bookkeeping entry in NiSource’s books and records and represent an unsecured contractual right to receive cash in the future. They are unfunded and subject to the rights of NiSource’s general creditors. One phantom stock unit is equal in value to one share of NiSource common stock. The phantom stock units also are credited with dividend equivalents, which are equal in value to dividends declared on shares of NiSource common stock and payable, at Messrs. Skaggs’ and Kettering’s election, in cash or credited to his account as additional phantom stock units. Their elections must be made in the calendar year prior to the year in which the dividend equivalents are credited. These phantom stock units are payable in cash upon Messrs. Skaggs’ or Kettering’s termination of employment, respectively, subject to the execution of a general release of claims. We expect that these phantom stock units held by Messrs. Skaggs and Kettering on the date of Separation will convert into CPG phantom stock units in a manner that preserves the value of the award following the Separation and that such CPG phantom stock units will be on substantially the same terms and conditions as the original NiSource phantom stock units.

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Potential Payments upon Termination of Employment

or a Change-in-Control of the Company

NiSource provides certain benefits to eligible employees, including the Named Executive Officers, upon certain types of termination of employment, including a termination of employment involving a Change-in-Control of NiSource. These benefits are in addition to the benefits to which the employees would be entitled upon a termination of employment generally (i.e., (i) vested retirement benefits accrued as of the date of termination, (ii) stock-based awards that are vested as of the date of termination and (iii) the right to continue medical coverage pursuant to COBRA). The incremental benefits that pertain to the Named Executive Officers are described below.

NiSource Executive Severance Policy. The NiSource Executive Severance Policy was established to provide severance pay and other benefits to terminated executive-level employees who satisfy the terms of the policy. No employee is eligible to receive benefits under the policy if termination of employment results in the employee being eligible for a payment under a Change-in-Control and Termination Agreement.

A participant becomes entitled to receive benefits under the policy only if he or she is terminated for any of the following reasons: (a) the employee’s position is eliminated due to a reduction in force or other restructuring; (b) the employee’s position is required by NiSource to relocate more than 50 miles from its current location and results in the employee having a longer commute of at least 20 miles and the employee chooses not to relocate; or (c) the employee is constructively terminated. Constructive termination means (1) the scope of the participant’s position is changed materially, (2) the participant’s base pay is reduced by a material amount or (3) the participant’s opportunity to earn a bonus under a corporate incentive plan of NiSource is materially reduced or is eliminated, and, in any such event, the participant chooses not to remain employed in such position.

Under the NiSource Executive Severance Policy, an eligible employee receives severance pay in the amount of 52 weeks of base salary at the rate in effect on the date of termination. The employee also receives: a lump sum payment equivalent to 130% of 52-weeks of COBRA (as defined in the Code and the Employee Retirement Income Security Act of 1974) continuation coverage premiums and outplacement services.

All of the Named Executive Officers are eligible to receive benefits under the NiSource Executive Severance Policy.

Change-in-Control and Termination Agreements and Employment Agreements. As of December 31, 2014, NiSource had Change-in-Control and Termination Agreements with each of the Named Executive Officers, which we expect to assume in connection with the Separation. NiSource entered into these agreements based upon its belief that they are in the best interests of its stockholders, they are designed to help ensure that in the event of extraordinary events, a thoroughly objective judgment is made on any potential corporate transaction, so that stockholder value is appropriately safeguarded and maximized. The Change-in-Control Agreements provide for cash severance benefits upon a double trigger (meaning there must be both a qualifying change-in-control and termination of employment). None of the agreements contains a “gross-up” provision for payments to executives for excise taxes incurred with respect to benefits received under a Change-in-Control Agreement. The Change-in-Control Agreements can be terminated on twelve months’ notice and provide for the payment of specified benefits if the executive terminates employment for “Good Reason” (as defined below) or is terminated by NiSource for any reason other than “Good Cause” (as defined below) within twenty-four months following certain Change-in-Control events.

For purposes of the Change-in-Control and Termination Agreements:

“Change-in-Control” shall be deemed to take place on the occurrence of any of the following events: (1) the acquisition by an entity, person or group (including all affiliates or associates of such entity, person or group) of beneficial ownership, as that term is defined in Rule 13d-3 under the Exchange Act, of capital stock of NiSource entitled to exercise more than 30% of the outstanding voting power of all capital stock of NiSource entitled to vote in elections of directors (“Voting Power”); (2) the effective time of: (i) a merger or consolidation

142

of NiSource with one or more other corporations unless the holders of the outstanding Voting Power of NiSource immediately prior to such merger or consolidation (other than the surviving or resulting corporation or any affiliate or associate thereof) hold at least 50% of the Voting Power of the surviving or resulting corporation (in substantially the same proportion as the Voting Power of NiSource immediately prior to such merger or consolidation), or (ii) a transfer of a substantial portion of the property of NiSource, other than to an entity of which NiSource owns at least 50% of the Voting Power; or (3) the election to the NiSource board of directors of candidates who were not recommended for election by the NiSource board of directors, if such candidates constitute a majority of those elected in that particular election (for this purpose, recommended directors will not include any candidate who becomes a member of the NiSource board of directors as a result of an actual or threatened election contest or proxy or consent solicitation on behalf of anyone other than the NiSource board of directors or as a result of any appointment, nomination, or other agreement intended to avoid or settle a contest or solicitation). Notwithstanding the foregoing, a Change-in-Control shall not be deemed to take place by virtue of any transaction in which the executive is a participant in a group effecting an acquisition of NiSource and, after such acquisition, the executive holds an equity interest in the acquiring entity.

“Good Cause” shall be deemed to exist if, and only if, NiSource notifies the executive, in writing, within 60 days of its knowledge that one of the following events occurred: (1) the executive has engaged in acts or omissions constituting dishonesty, intentional breach of fiduciary obligation or intentional wrongdoing or malfeasance, in each case that results in substantial harm to NiSource; or (2) the executive has been convicted of a criminal violation involving fraud or dishonesty.

“Good Reason” shall be deemed to exist if, and only if: (1) there is a significant diminution in the nature or the scope of the executive’s authorities or duties; (2) there is a significant reduction in the executive’s monthly rate of base salary and the executive’s opportunity to earn a bonus under an incentive bonus compensation plan maintained by NiSource or the executive’s benefits; (3) NiSource changes by 50 miles or more the principal location at which the executive is required to perform services as of the date of a Change-in-Control; or (4) there is a material breach of the Change-in-Control Agreement.

The Change-in-Control Agreements provide for a payment of two (three in the case of Mr. Skaggs) times the executive’s current annual base salary and target incentive bonus compensation. The executive will also receive a pro rata portion of the executive’s targeted incentive bonus for the year of termination. The Change-in-Control Agreements also provide that in the event of a Change-in-Control, the executive’s total Change-in-Control payments will equal one dollar less than the amount that would trigger an excise tax gross up; provided, however, that if the total payment due, after being reduced for federal, state, local and other taxes is greater than the reduced amount, the executive will receive the total Change-in-Control payments due (without a gross-up).

In addition, the Change-in-Control Agreements provide for the executives to receive 130% of the COBRA continuation premiums due for the two-year period (three in the case of Mr. Skaggs) following termination. In the event of a Change-in-Control, all performance share awards which have been granted to each of the Named Executive Officers under the Omnibus Plan and are outstanding as of December 31, 2014 will immediately vest. Restricted stock unit awards granted before January 1, 2014 and outstanding as of December 31, 2014 will immediately vest and restricted stock unit awards granted during 2014 and outstanding as of December 31, 2014 vest only upon a termination in connection with a Change-in-Control.

Pursuant to a letter agreement dated May 14, 2008 between NiSource and Mr. Smith, if NiSource terminates his employment other than for cause or if he terminates his employment for good reason, he is entitled to receive the following severance benefits in lieu of severance benefits under the Executive Severance Policy: (1) a lump sum payment equal to his annual base salary; (2) a lump sum payment equal to his prorated target incentive for the year in which termination occurs; (3) a lump sum payment equal to 130% of COBRA continuation coverage premiums for one year; and (4) reasonable outplacement services. We expect to assume NiSource’s rights and obligations under this letter agreement in connection with the Separation.

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Potential Payments Upon Termination of Employment. The table below represents amounts payable at, following, or in connection with the events described below, assuming that such events occurred on December 31, 2014 for each of the Named Executive Officers.


Name	Severance ($)		Pro Rata Target Annual/ Retention Bonus Payment ($)		Equity Grants ($)		Welfare Benefits ($)		Outplacement ($)		Total Payment ($)
Robert C. Skaggs, Jr.
Voluntary Termination⁽¹⁾		—		—		5,932,607		—		—		5,932,607
Retirement⁽²⁾		—		—		9,797,578		—		—		9,797,578
Disability⁽²⁾		—		—		9,797,578		—		—		9,797,578
Death⁽²⁾		—		—		9,797,578		—		—		9,797,578
Involuntary Termination⁽³⁾		980,000		—		—		11,887		25,000		1,016,887
Change-in-Control⁽⁴⁾		6,615,000		1,225,000		5,093,327		43,665		25,000		13,001,992
Stephen P. Smith
Voluntary Termination⁽¹⁾		—		—		—		—		—		—
Retirement⁽²⁾		—		—		—		—		—		—
Disability⁽²⁾		—		—		3,999,230		—		—		3,999,230
Death⁽²⁾		—		—		3,999,230		—		—		3,999,230
Involuntary Termination⁽³⁾		600,000		420,000		—		19,233		25,000		1,064,233
Change-in-Control⁽⁴⁾		2,040,000		420,000		5,941,430		42,735		25,000		8,469,165
Glen L. Kettering
Voluntary Termination⁽¹⁾		—		—		—		—		—		—
Retirement⁽²⁾		—		—		1,784,864		—		—		1,784,864
Disability⁽²⁾		—		—		1,784,864		—		—		1,784,864
Death⁽²⁾		—		—		1,784,864		—		—		1,784,864
Involuntary Termination⁽³⁾		500,000		—		—		19,268		25,000		544,268
Change-in-Control⁽⁴⁾		1,600,000		300,000		1,362,021		42,094		25,000		3,329,115
Shawn L. Patterson
Voluntary Termination⁽¹⁾		—		—		—		—		—		—
Retirement⁽²⁾		—		—		—		—		—		—
Disability⁽²⁾		—		—		1,301,615		—		—		1,301,615
Death⁽²⁾		—		—		1,301,615		—		—		1,301,615
Involuntary Termination⁽³⁾		360,000		400,000		—		19,572		25,000		804,572
Change-in-Control⁽⁴⁾		1,080,000		580,000		3,539,694		41,705		25,000		5,266,399
Stanley G. Chapman, III
Voluntary Termination⁽¹⁾		—		—		—		—		—		—
Retirement⁽²⁾		—		—		—		—		—		—
Disability⁽²⁾		—		—		1,431,124		—		—		1,431,124
Death⁽²⁾		—		—		1,431,124		—		—		1,431,124
Involuntary Termination⁽³⁾		395,000		300,000		—		11,624		25,000		731,624
Change-in-Control⁽⁴⁾		1,185,000		497,500		3,436,317		26,059		25,000		5,169,876

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(1)

Amounts payable to each of the Named Executive Officers as shown in the Pension Benefits Table and the Nonqualified Deferred Compensation Table and under the tax-qualified, nondiscriminatory 401(k) Plan are not included. Upon voluntary termination, Mr. Skaggs would receive 64,043 shares under his 2009 Restricted Stock Unit Award, 46,685 shares under his special 2010 Restricted Stock Unit Award, and 29,126 shares under his 2010 annual Restricted Stock Unit Award. The original vesting date for these shares has passed. However, these shares were subject to delayed vesting in accordance with the terms of the award agreements due to limitations on deductibility under Section 162(m) of the Code. These shares are payable to Mr. Skaggs on the earlier to occur of his termination of employment, the date he is no longer subject to Section 162(m) of the Code or the date that such shares could be paid to him and be deductible under Section 162(m) of the Code. In addition, Messrs. Skaggs and Kettering would receive the pro-rated equity amounts reflected below in note 2 because they are retirement eligible at termination.

(2)

Special vesting rules apply in the event of Retirement, Disability or death pursuant to the terms and conditions of our equity award agreements. Only Mr. Skaggs and Mr. Kettering were eligible for Retirement as of December 31, 2014. For Mr. Skaggs, 230,966 shares would have pro-rata vested as a result of his Retirement, Disability or death. For Mr. Kettering, 42,076 shares would have pro-rata vested as a result of his Retirement, Disability or death. For each of the other Named Executive Officers, the number of shares that would have vested in the event of the Disability or death is as follows: Mr. Smith, 94,277 shares; Mr. Patterson, 30,684 shares; and Mr. Chapman, 33,737 shares. The value of the equity grants was determined by multiplying the closing price of NiSource’s common stock on the NYSE on December 31, 2014 of $42.42 by the number of shares that would have vested upon the Retirement, Disability or death, as applicable, of the Named Executive Officer and, with respect to performance shares, assumes a payout at the target level. No performance shares are actually payable until such time as the NiSource ONC Committee certifies attainment of the applicable performance goals, except in the case of death with more than 12 months remaining in the performance period, in which case the performance shares are payable at target levels regardless of NiSource ONC Committee certification.

(3)

Amounts shown reflect payments to be made upon the involuntary termination of the Named Executive Officer under the NiSource Executive Severance Policy described above, or in the case of Mr. Smith, pursuant to the terms of his employment agreement. The amounts shown for Mr. Skaggs and Mr. Kettering do not include equity grants that would pro-rata vest solely as a result of their eligibility for retirement. In addition, the amount shown for Mr. Skaggs does not include the shares subject to delayed vesting due to limitations on deductibility under Section 162(m) of the Code referred to in note (1) above, which are payable to him on the earlier to occur of his termination of employment, the date he is no longer subject to Section 162(m) of the Code or the date that such shares could be paid to him and be deductible under Section 162(m) of the Code. The amounts for Messrs. Patterson and Chapman include the unpaid portion of their retention bonuses pursuant to the terms of their respective 2014 retention bonus agreements.

(4)

Amounts shown reflect payments to be made upon termination of employment in the event of a Change-in-Control of NiSource under the Change-in-Control and Termination Agreements described above. As described above, the Change-in-Control Agreements entered into with each of the Named Executive Officers do not contain an excise tax gross-up. The revised Change-in-Control and Termination Agreements provide that in the event of a Change-in-Control, the executive’s total Change-in-Control payments will equal one dollar less than the amount that would trigger an excise tax gross-up. However, if the total payment due, after being reduced for federal, state, local and other taxes is greater than the reduced amount, the executive will receive the total Change-in-Control payments due (without a gross-up). In addition, the amounts shown for Mr. Skaggs’ and Mr. Kettering’s equity grants do not include the shares referred to in note (2) above, which would automatically pro-rata vest in the event of their termination of employment regardless of a Change-in-Control; and, the amount shown for Mr. Skaggs does not include the shares subject to delayed vesting due to limitations on deductibility under Section 162(m) of the Code referred to in note (1) above, which are payable to him in the event of his termination of employment regardless of a Change-in-Control. The amounts for Messrs. Patterson and Chapman include the unpaid portion of their retention bonuses pursuant to the terms of their respective 2014 retention bonus agreements.

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SECURITY OWNERSHIP OF MANAGEMENT, DIRECTORS AND PRINCIPAL STOCKHOLDERS

The following table sets forth the anticipated beneficial ownership of our common stock immediately following the Distribution by (i) each of our directors, (ii) each of our Named Executive Officers, (iii) our directors and executive officers as a group and (iv) those persons that we expect to be the beneficial owners of more than five percent of our outstanding common stock immediately following the Distribution. The table is based on information available to us concerning ownership of NiSource common stock as of May 13, 2015 and the distribution ratio of one share of our common stock for each share of NiSource common stock. Percentages were calculated based upon 317,471,813 shares of our common stock outstanding immediately following the Distribution, which represents the number of shares of NiSource common stock outstanding as of May 13, 2015. Beneficial ownership reflects sole voting and sole investment power, unless otherwise noted. The number of shares listed below does not reflect the conversion of NiSource equity awards into CPG equity awards, as described elsewhere in this Information Statement, as such converted awards will not be determinable until after the Distribution Date. The address of each of the directors and executive officers shown in the table below is c/o Columbia Pipeline Group, Inc., 5151 San Felipe St., Suite 2500, Houston, Texas 77056.


Name	Amount and Nature of Beneficial Ownership⁽¹⁾		Percentage of Class
5% Owners

The Vanguard Group⁽²⁾		24,716,611		7.8	%

T. Rowe Price Associates, Inc.⁽³⁾		21,991,926		6.9	%

BlackRock, Inc.⁽⁴⁾		21,005,426		6.6	%

Deutsche Bank AG⁽⁵⁾		19,417,886		6.1	%

State Street Corporation⁽⁶⁾		16,275,486		5.1	%

FMR LLC⁽⁷⁾		16,099,997		5.1	%

Directors

Sigmund L. Cornelius		11,453		*

Marty R. Kittrell		4,255		*

W. Lee Nutter		118,380		*

Deborah S. Parker		3,410		*

Lester P. Silverman		—		*

Teresa A. Taylor		4,444		*

Named Executive Officers

Stanley G. Chapman, III		17,707		*

Glen L. Kettering⁽⁸⁾		109,766		*

Shawn L. Patterson		42,160		*

Robert C. Skaggs, Jr.⁽⁸⁾		863,588		*

Stephen P. Smith		185,687		*

Directors and executive officers as a group (14 persons)		1,432,744		*

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*	Less than 1%

(1)	The number of shares owned includes shares held in NiSource’s 401(k) Plan.

(2)

This information is derived from an amended Schedule 13G filed with the SEC by The Vanguard Group on February 10, 2015 with respect to shares of NiSource common stock. According to the amended Schedule 13G, The Vanguard Group has sole voting power with respect to 568,067 NiSource shares, sole dispositive power with respect to 568,067 NiSource shares and shared dispositive power with respect to 513,214 NiSource shares reported as beneficially owned. The principal business address of The Vanguard Group is 100 Vanguard Blvd., Malvern, PA 19355.

(3)

This information is derived from an amended Schedule 13G filed with the SEC by T. Rowe Price Associates, Inc. on February 13, 2015 with respect to shares of NiSource common stock. According to the amended Schedule 13G, T. Rowe Price Associates, Inc. has sole voting power with respect to 6,960,111 NiSource shares and sole dispositive power with respect to 21,991,926 of the NiSource shares reported as beneficially owned. The principal business address of T. Rowe Price is 100 E. Pratt Street, Baltimore, Maryland 21202.

(4)

This information is derived from an amended Schedule 13G filed with the SEC by BlackRock, Inc. on January 29, 2015 with respect to shares of NiSource common stock. According to the amended Schedule 13G, BlackRock, Inc. has sole voting power with respect to 18,198,312 NiSource shares and sole dispositive power with respect to 21,005,426 NiSource shares reported as beneficially owned. The principal business address of BlackRock, Inc. is 40 East 52nd Street, New York, New York 10022.

(5)

This information is derived from a Schedule 13G filed with the SEC by Deutsche Bank AG on February 17, 2015. Includes NiSource shares held by Deutsche Bank AG and NiSource shares beneficially owned by the Asset and Wealth Management business group (collectively, “AWM”) of Deutsche Bank AG and its subsidiaries and affiliates, including shares held by Deutsche Investment Management Americas, Deutsche Asset & Wealth Management International GmbH, Deutsche Asset & Wealth Management Investment GmbH, DBX Advisors LLC, DWS Investment S.A., Luxembourg, Deutsche Bank Trust Company National Association, Deutsche Bank Securities, Inc. and Deutsche Bank AG, London Branch (collectively, the “DB AWM Entities”). According to the Schedule 13G, Deutsche Bank AG is deemed to beneficially own the NiSource shares held by the DB AWM Entities. Also, according to the Schedule 13G, Deutsche Bank AG has sole voting power with respect to 19,331,470 NiSource shares, sole dispositive power with respect to 19,415,886 NiSource shares and shared dispositive power with respect to 2,000 NiSource shares reported as beneficially owned. The principal business address of Deutsche Bank AG and each of the DB AWM Entities is Taunusanlage 12, 60325 Frankfurt am Main, Federal Republic of Germany. The detailed holdings of the DB AWM Entities are provided below:


Entity Name	Number of Shares Beneficially Owned with Sole Voting Power		Number of Shares Beneficially Owned with Sole Dispositive Power		Number of Shares Beneficially Owned with Shared Dispositive Power
Deutsche Investment Management Americas		8,333,011		8,347,011		0
Deutsche Bank Trust Company National Association		4,150		4,150		2,000
Deutsche Bank Securities, Inc		0		15,681		0
DBX Advisors LLC		4,615		4,615		0
Deutsche Asset & Wealth Management International GmbH		10,881,572		10,954,407		0
Deutsche Asset & Wealth Management Investment GmbH		87,422		87,422		0
DWS Investment S.A., Luxembourg		700		700		0
Deutsche Bank AG, London Branch		0		1,900		0

(6)	This information is derived from a Schedule 13G filed with the SEC by State Street Corporation on February 12, 2015 with respect to shares of NiSource common stock. According to the Schedule 13G, State

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Street Corporation has shared voting power with respect to 16,275,486 NiSource shares and shared dispositive power with respect to 16,275,486 NiSource shares reported as beneficially owned. The principal business address of State Street Corporation is State Street Financial Center, One Lincoln Street, Boston, Massachusetts 02111.

(7)

This information is derived from a Schedule 13G filed with the SEC by FMR LLC on February 13, 2015 with respect to shares of NiSource common stock. FMR LLC has sole voting power with respect to 298,188 NiSource shares and sole dispositive power with respect to 16,099,997 NiSource shares reported as beneficially owned. According to the Schedule 13G, shares held by FMR LLC may be deemed to be beneficially owned by each of Mr. Edward C. Johnson, III and Ms. Abigail P. Johnson. Members of the family of Mr. Johnson, including Ms. Johnson, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The principal business address of FMR LLC is 245 Summer Street, Boston, Massachusetts 02210.

(8)	Mr. Skaggs is also a director. The number of shares reported for Mr. Skaggs includes shares owned by the trusts over which Mr. Skaggs maintains investment control and of which he and his immediate family members are the sole beneficiaries.

Certain of the directors and Named Executive Officers own common units representing limited partnership interests of the MLP, our subsidiary which we control and in which we have a 46.5% ownership interest through our subsidiary, CEG. The table below shows the number of common units beneficially owned by such persons as of May 13, 2015. Beneficial ownership reflects sole voting and sole investment power.


Name of Beneficial Owner	Amount and Nature of Beneficial Ownership of MLP Common Units⁽¹⁾
Stanley G. Chapman, III		5,000
Sigmund L. Cornelius		4,400
Glen L. Kettering		1,300
Marty R. Kittrell		—
W. Lee Nutter		25,000
Deborah S. Parker		—
Shawn L. Patterson		1,100
Lester P. Silverman		—
Robert C. Skaggs, Jr.		37,500
Stephen P. Smith		37,500
Teresa A. Taylor		3,000
All directors and executive officers as a group (14 persons)		128,400

(1)	The percentage of common units owned by any director or Named Executive Officer, or all directors and executive officers as a group, does not exceed one percent of the common units outstanding as of May 13, 2015.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Policies and Procedures with Respect to Transactions with Related Persons

We expect that our board of directors will establish policies and procedures with respect to the review, approval and ratification of any transactions with related persons as set forth in our Audit and Risk Committee Charter and the Code of Business Conduct.

Under its Charter, the Audit and Risk Committee will be charged with the review of reports and disclosures of insider and affiliated party transactions. Under the Code of Business Conduct, the following situations must be reviewed if they involve a direct or indirect interest of any director, executive officer or employee (including immediate family members):

•

owning more than a 10% equity interest or a general partner interest in any entity that transacts business with the Company (including lending or leasing transactions), if the total amount involved in such transactions exceeds $120,000;

•

selling anything to the Company or buying anything from the Company (including lending or leasing transactions, but excluding the receipt of utility service from the Company at tariff rates), if the total amount involved in such transactions exceeds $120,000;

•

consulting for or being employed by a competitor; and

•

being in the position of supervising, reviewing or having any influence on the job evaluation, pay or benefit of any immediate family member.

Related party transactions requiring review under the Code of Business Conduct will be annually reviewed and ratified by the Audit and Risk Committee. Directors, individuals subject to Section 16 of the Exchange Act and senior executive officers will be expected to raise any potential transactions involving a conflict of interest that relates to them with the Audit and Risk Committee so that they may be reviewed in a prompt manner.

Agreements with NiSource Relating to the Separation

As part of the Separation, we will enter into a Separation and Distribution Agreement and several other agreements to effect the Separation and provide a framework for our relationship with NiSource after the Separation. These agreements will provide for the allocation between us and NiSource of the assets, liabilities and obligations of NiSource and its subsidiaries, and will govern the relationship between CPG and NiSource after the Separation.

In addition to the Separation and Distribution Agreement, the other principal agreements to be entered into with NiSource include:

•

a Tax Allocation Agreement;

•

Transition Services Agreements; and

•

an Employee Matters Agreement.

In addition, NiSource Corporate Services and Columbia Pipeline Group Services Company have entered into a Trademark License Agreement.

The summaries of these agreements set forth below are qualified in their entirety by reference to the full text of the applicable agreements, which are included as exhibits to our registration statement on Form 10, of which this Information Statement is a part.

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Separation and Distribution Agreement

The Separation and Distribution Agreement will contain the key provisions relating to the separation of our businesses from NiSource. It will also contain other agreements that govern certain aspects of our relationship with NiSource that will continue after the completion of the Separation.

Transfer of Assets and Assumption of Liabilities. The Separation and Distribution Agreement will identify assets and rights to be transferred, liabilities to be assumed and contracts to be assigned as part of the Separation.

The Distribution. The Separation and Distribution Agreement will also govern the rights and obligations of the parties regarding the Distribution. Prior to the Distribution, the number of shares of our common stock held by NiSource will be increased to the number of shares of our common stock distributable in the Distribution. NiSource will cause its agents to distribute all of the issued and outstanding shares of our common stock to NiSource stockholders who hold NiSource shares as of the Record Date.

Additionally, the Separation and Distribution Agreement will provide that the Distribution is subject to several conditions that must be satisfied or waived by NiSource in its sole discretion. For further information regarding these conditions, see the section entitled “The Separation—Conditions to the Distribution” beginning on page 71 of this Information Statement. NiSource may, in its sole discretion, determine the Record Date and the Distribution Date and any necessary or appropriate procedures in connection with the Distribution, and may at any time prior to the Distribution decide to abandon the Distribution or modify or change the terms of the Distribution.

Termination. The Separation and Distribution Agreement will provide that it may be terminated and the Distribution and the Separation may be abandoned at any time prior to the Distribution Date by NiSource, in its sole discretion.

Releases, Allocation of Liabilities and Indemnification. The Separation and Distribution Agreement will provide for a full and complete release and discharge of all liabilities existing or arising from or based on facts existing prior to the Separation, between or among us or any of our affiliates, and NiSource or any of its affiliates (other than us), except as set forth in the Separation and Distribution Agreement.

We will be liable for and agree to perform all liabilities with respect to our business, which we refer to as the “CPG liabilities.” Those liabilities will include, (i) all liabilities of CPG and its subsidiaries to the extent based upon or arising out of the business and operations of CPG and its subsidiaries, (ii) all liabilities of NiSource and its subsidiaries to the extent based upon or arising out of the business and operations of CPG and its subsidiaries, (iii) all liabilities based upon or arising out of financial instruments of CPG and its subsidiaries and (iv) all liabilities on our unaudited pro forma consolidated balance sheet as of March 31, 2015 and all liabilities incurred by CPG or NiSource of the type that would have been included on such balance sheet had they been incurred on or prior to the date thereof.

NiSource will be liable for and agrees to perform all liabilities with respect to its business, which we refer to as the “NiSource liabilities.” Those liabilities will include, (i) all liabilities of NiSource and its subsidiaries to the extent based upon or arising out of the businesses retained by NiSource, (ii) all liabilities of CPG and its subsidiaries to the extent based upon or arising out of the businesses retained by NiSource and (iii) all liabilities based upon or arising out of financial instruments of NiSource and its subsidiaries.

In addition, the Separation and Distribution Agreement will provide for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of NiSource’s retained businesses with NiSource. Specifically, subject to certain exceptions set forth in the Separation and Distribution Agreement, we anticipate that we will agree to assume liability for, and to indemnify and hold harmless NiSource, its affiliates and its directors, officers

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and employees against, certain liabilities relating to our business and the Separation, including all liabilities relating to, arising out of or resulting from:

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the failure by CPG or any other person to pay, perform or otherwise promptly discharge any CPG liability;

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any CPG liability;

•

our business (including any businesses or assets that have been divested prior to the Separation or thereafter) as conducted on, at any time prior to or at any time after the Distribution;

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except to the extent provided in the Separation and Distribution Agreement, any claim that the information included in our registration statement on Form 10, this Information Statement or our registration statements on Form S-8 registering shares of common stock subject to equity-based awards (“our Form S-8”) is or was false or misleading with respect to any material fact or omits or omitted to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading;

•

the use by us after the Separation of the name “NiSource” or any variation thereof, or other trademarks, trade names, logos or identifiers using any of such names or otherwise owned by or licensed to NiSource;

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the breach by us of any covenant or agreement set forth in any agreement entered into in connection with the Separation;

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any item or matter for which reimbursement or indemnification is to be provided by CPG in accordance with the terms of the Employee Matters Agreement; and

•

any of our financial instruments.

It is expected that NiSource will agree to indemnify and hold harmless us, our affiliates and our directors, officers and employees from and against all liabilities relating to, arising out of or resulting from:

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the failure by NiSource or any other person to pay, perform or otherwise promptly discharge any NiSource liability;

•

any NiSource liability;

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the businesses retained by NiSource (including any businesses or assets that have been divested prior to the Separation or thereafter) as conducted on, at any time prior to or at any time after the Distribution;

•

solely with respect to information identified in the schedules to the Separation and Distribution Agreement as being supplied by or the responsibility of NiSource, any claim that the information included in our registration statement on Form 10, this Information Statement or our Form S-8 is or was false or misleading with respect to any material fact or omits or omitted to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading;

•

the breach by NiSource of any covenant or agreement set forth in any agreement entered into in connection with the Separation;

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any item or matter for which reimbursement or indemnification is to be provided by NiSource in accordance with the terms of the Employee Matters Agreement; and

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any of NiSource’s financial instruments.

The Separation and Distribution Agreement also will establish procedures with respect to claims subject to indemnification and related matters. Indemnification with respect to taxes and employee benefits will be governed by the Tax Allocation Agreement and the Employee Matters Agreement, respectively.

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Access to Information. The Separation and Distribution Agreement will provide that the parties will exchange certain information reasonably required to comply with requirements imposed on the requesting party by a government authority for use in any proceeding or to satisfy audit, accounting or similar requirements, for use in compensation, benefit or welfare plan administration or other bona fide business purposes, or to comply with its obligations under the Separation and Distribution Agreement or any ancillary agreement. In addition, the parties will use commercially reasonable efforts to make available to each other past and present directors, officers, other employees and agents as witnesses in any legal, administrative or other proceeding in which the other party may become involved, unless NiSource and CPG (or their respective subsidiaries) are adverse to each other in such proceeding.

Expenses. Except as expressly set forth in the Separation and Distribution Agreement or in any related agreement, each of NiSource and CPG will pay all third-party fees, costs and expenses paid or incurred by it in connection with the Separation. However, NiSource generally will pay non-recurring third-party fees, costs and expenses arising from the Separation incurred prior to the Distribution Date and CPG will pay all third-party fees, costs and expenses incurred prior to the Distribution Date that are expected to benefit CPG following the Distribution in the ordinary course of business.

Tax Allocation Agreement

Before the Separation, we will enter into a Tax Allocation Agreement with NiSource. The Tax Allocation Agreement will govern the respective rights, responsibilities and obligations of NiSource and us with respect to certain tax liabilities and benefits, tax attributes, tax returns, tax contests and other related matters. In general, under the Tax Allocation Agreement, we will be responsible for all taxes attributable to our business, and we will agree to indemnify NiSource for these taxes. NiSource will be responsible for all taxes to the extent such taxes are not attributable to our business, and NiSource will agree to indemnify us to the extent we are not responsible for these taxes. As we were a subsidiary of NiSource prior to the Distribution, we may be held liable for the full amount of any consolidated federal income taxes due with respect to the NiSource group for taxable periods ending on or prior to the Distribution. Although we will continue to have legal liability for these taxes following the Distribution, under the Tax Allocation Agreement, NiSource will agree to indemnify us for amounts relating to this liability to the extent not attributable to our business. Though binding as between NiSource and us, the Tax Allocation Agreement will not be binding on the IRS.

The Tax Allocation Agreement will also contain restrictions on our ability to take actions that could cause the Distribution to fail to qualify for tax-free treatment. These restrictions will apply for the two-year period after the Distribution, unless (1) we obtain the consent of NiSource, a private letter ruling from the IRS or an unqualified opinion of a nationally recognized law or accounting firm that such action will not cause the Distribution to fail to qualify for tax-free treatment, and (2) any such letter ruling or opinion, as the case may be, is acceptable to NiSource. Moreover, the Tax Allocation Agreement generally will provide that we are responsible for any taxes and certain associated costs, expenses and damages imposed on NiSource as a result of the failure of the Distribution to qualify for tax-free treatment if such failure is attributable to certain actions taken by or in respect of us after the Distribution, regardless of whether the actions occur more than two years after the Distribution, NiSource consents to such actions or CPG obtains a favorable letter ruling or tax opinion. In addition, in the event the Distribution were determined to be taxable and neither we nor NiSource were at fault, we would be responsible for a portion of the taxes imposed on NiSource as a result of such determination.

Transition Services Agreements

NiSource and CPG will enter into Transition Services Agreements, which will provide for the provision of certain transitional services by NiSource to CPG, and vice versa. The services may include the provision of administrative and other services identified by the parties. The Transition Services Agreements will generally provide for a term of up to 24 months. The charge for these interim services is expected to be based on actual costs incurred by the party rendering the services without profit. CPG expects to pay NiSource approximately $4.9 million in the aggregate for services provided by NiSource to CPG pursuant to the Transition Services Agreement.

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The Transition Services Agreements will provide that any service may be terminated by the service recipient upon advance notice to the service provider or by either party if the other party has materially breached its obligations under the agreement relating to the service and has not cured the breach within an agreed upon period of time.

In general, neither NiSource nor CPG will be liable to the other in connection with any service provided under the Transition Services Agreements except in the case of gross negligence or willful misconduct.

NiSource and CPG will perform the transition services in the manner and at the level of service substantially similar to that immediately prior to the Distribution, and either company’s use of the services will not be substantially greater than the level of use required by either company immediately prior to the Distribution. The companies will use all commercially reasonable efforts to end their respective use of the transition services as soon as is reasonably possible and no later than the applicable services termination date specified in the agreements. Each company will have the right to terminate any transition service that the other party is providing upon 30 days notice.

Employee Matters Agreement

NiSource and CPG will enter into an Employee Matters Agreement providing for their respective obligations to employees and former employees who are or were associated with CPG (including those employees who transfer employment from NiSource to CPG prior to the Separation) and for other employment and employee benefits matters. The Employee Matters Agreement may also provide for sharing of specific employee and former employee information to enable NiSource and CPG to comply with their respective obligations.

Under the terms of the Employee Matters Agreement, CPG generally will assume all liabilities and assets relating to employee benefits for current and former CPG employees, and NiSource generally will retain all liabilities and assets relating to employee benefits for current and former NiSource employees. We also anticipate that CPG will assume all assets and liabilities related to benefits for current and former CPG employees in NiSource’s defined contribution plans.

In addition, the Employee Matters Agreement will address the treatment of outstanding NiSource equity awards in connection with the Separation, as described in “The Separation—Treatment of Equity-Based Compensation.”

Trademark License Agreement

Under the Trademark License Agreement between NiSource Corporate Services Company (“Licensor”) and Columbia Pipeline Group Services Company (“Licensee”), Licensee and its present and future affiliates receive a royalty-free, perpetual, irrevocable, exclusive license to use licensed marks within the United States in connection with services and lines of business (transportation, gathering, processing, storage of natural gas and oil and related services) currently conducted by CPG or any of its subsidiaries (the “Licensed Marks”). Licensed Marks include any registered or unregistered trademarks, trade names, logos, and/or service marks owned by Licensor or its affiliates containing the term “COLUMBIA.”

The Trademark License Agreement contains certain limitations on the license grant described above, including restrictions on sublicensing rights to use the Licensed Marks and requirements to comply with certain quality control standards. Licensor retains the right to sue for infringement of the Licensed Marks unless Licensor fails to act within 90 days of receiving notice of infringement or fails to diligently prosecute an infringement suit. The term of the Trademark License Agreement is perpetual and can only be terminated by mutual written agreement of the parties.

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Other Agreements with NiSource

Columbia Gas of Ohio, an affiliate of NiSource, accounted for approximately 13% of our contracted revenues for the year ended December 31, 2014. These sales have historically been made on arm’s-length terms. We expect this commercial activity to continue on similar terms following the Separation, but we cannot provide any assurance that our relationship with Columbia Gas of Ohio will continue on similar terms, or continue at all.

Additionally, CPG is a party to certain operating and maintenance agreements with NiSource on arm’s-length terms in the ordinary course of business, and these agreements will not be terminated in connection with the Separation.

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DESCRIPTION OF CAPITAL STOCK

Overview

Our certificate of incorporation and bylaws will be amended and restated prior to the Separation. The following is a summary of certain provisions of Delaware law and the material terms of our capital stock that will be contained in our amended and restated certificate of incorporation (“our charter”) and our amended and restated bylaws (“our bylaws”). The following descriptions do not purport to be complete statements of the relevant provisions of our charter, our bylaws or the DGCL. You should refer to our charter and bylaws, which are included as exhibits to our registration statement on Form 10, of which this Information Statement is a part, along with the applicable provisions of the DGCL.

Authorized Capital Stock

Immediately following the Distribution, our authorized capital stock will consist of 2,000,000,000 shares of common stock, par value $0.01 per share, and 80,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

Shares Outstanding. Immediately following the Distribution, we estimate that approximately 317,535,860 shares of our common stock will be issued and outstanding, based on the number of shares of NiSource common stock outstanding as of May 28, 2015 and applying the distribution ratio of one share of our common stock for each share of NiSource common stock to be distributed to NiSource stockholders who hold NiSource common stock as of the Record Date. In addition, based on the closing price of NiSource common stock on May 19, 2015, we expect that approximately 2.2 million shares of our common stock will be reserved for issuance upon the settlement of outstanding NiSource equity compensation awards that are converted to CPG equity compensation awards in connection with the Distribution. The actual number of shares of our common stock outstanding immediately following the Distribution will depend on the actual number of shares of NiSource common stock outstanding on the Record Date and will reflect any issuance of new shares of NiSource common stock pursuant to NiSource’s equity plans, in each case on or prior to the Record Date.

Upon completion of the Distribution, all of the outstanding shares of our common stock will be validly issued, fully paid and non-assessable.

Dividends. Holders of shares of our common stock are entitled to receive dividends when, as and if declared by our board of directors out of funds legally available for that purpose, subject to any preferential rights of holders of any outstanding shares of preferred stock and any other class or series of stock having preference over the common stock as to dividends. All decisions regarding our payment of dividends will be made by our board of directors from time to time in accordance with applicable law. Following the Separation, we expect to establish a dividend payout ratio target, which reflects the percentage of our recurring earnings expected to be paid as dividends.

Voting Rights. The holders of our common stock are entitled to one vote for each share held of record on all matters submitted to a vote of our stockholders. In matters other than the election of directors, stockholder approval requires the affirmative vote of a majority of the voting power of our capital stock present in person or represented by proxy at the meeting and entitled to vote on the matter, voting as a single class, unless the matter is one upon which, by express provision of law, our charter or our bylaws, a different vote is required. Subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, election of directors is determined by a plurality of the votes cast.

In addition to any other vote that may be required by law, applicable stock exchange rule or the terms of any series of our preferred stock, amendments to our certificate of incorporation must be approved by at least a majority of the voting power of all then outstanding shares of capital stock entitled to vote generally in the

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election of directors, voting as a single class. However, the vote of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting as a single class, is required to amend certain provisions of our charter, including the provisions relating to the classified board of directors, stockholder action by written consent and stockholder amendment of our bylaws or charter.

Our bylaws may be amended by the vote of at least a majority of our board of directors or the holders of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Other Rights. Subject to the rights of any holders of preferred stock, upon our liquidation, dissolution or winding-up, after payment or provision for payment of our debts and other liabilities, the holders of our common stock are entitled to share ratably in all of our assets available for distribution to our stockholders.

No shares of our common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or any other of our securities. There are no subscription rights, conversion rights or sinking fund provisions applicable to our common stock.

Preferred Stock

Our board of directors will have the authority, without action by our stockholders, to designate and issue our preferred stock in one or more series and to designate the rights, preferences, limitations and privileges of each series of preferred stock, which may be greater than the rights of our common stock. It is not possible to state the actual effect of the issuance of any shares of our preferred stock upon the rights of holders of our common stock until our board of directors determines the specific rights of the holders of our preferred stock. However, the effects of the issuance of any shares of our preferred stock upon the rights of holders of our common stock might include, among other things:

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restricting dividends on our common stock,

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diluting the voting power of our common stock,

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impairing the liquidation rights of our common stock, and

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delaying or preventing a change in control without further action by our stockholders.

Upon completion of the Distribution, no shares of our preferred stock will be outstanding, and we have no present plans to issue any shares of preferred stock.

Certain Provisions of Delaware Law, Our Charter and Our Bylaws

Certain provisions of Delaware law, our charter and our bylaws summarized below may have an anti-takeover effect and may delay, deter or prevent a tender offer or takeover attempt that some stockholders might consider to be in their best interests, including attempts that might result in a premium being paid over the market price for shares of our common stock. These provisions:

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encourage potential acquirers to deal directly with our board of directors,

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give our board of directors the time and leverage to evaluate the fairness of the proposal to all stockholders,

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enhance continuity and stability in the composition of our board of directors and in the policies formulated by our board of directors, and

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discourage certain tactics that may be used in proxy fights.

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Undesignated Preferred Stock. Without any vote or other action by our stockholders, our board of directors will have the ability to designate and issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of CPG. These and other provisions may defer hostile takeovers or delay changes of control of our management.

Classified Board of Directors until the 2018 Annual Meeting of Stockholders. Subject to the rights of holders of any series of our preferred stock with respect to the election of directors, our charter will provide for our board of directors to be divided into three classes as nearly equal in size as practicable. The term of the first class of directors will expire upon the election of directors at our 2016 annual meeting of stockholders; the term of the second class of directors will expire upon the election of directors at our 2017 annual meeting of stockholders and the term of the third class of directors will expire upon the election of directors at our 2018 annual meeting of stockholders. Directors elected at the 2016 and 2017 annual meetings of stockholders will hold office until the 2018 annual meeting of stockholders. Commencing with the 2018 annual meeting of stockholders, each director will be elected annually for a term of one year.

No Cumulative Voting. Our charter will provide that holders of shares of our common stock are not entitled to cumulate their votes in the election of directors.

No Stockholder Action by Written Consent; Special Meetings. Except as otherwise expressly provided by the terms of any series of our preferred stock permitting the holders of such series to act by written consent, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders, and our charter will specifically deny the ability of our stockholders to consent in writing to the taking of any action. Further, our charter and our bylaws will provide that special meetings may be called only by the Chairperson of our board of directors, our Chief Executive Officer or our board of directors, by resolution adopted by a majority of the entire board of directors.

Requirements for Advance Notification of Stockholder Nomination and Proposals. Our bylaws will establish advance notice procedures with respect to stockholder proposals and nomination of candidates for election as directors other than nominations made by or at the direction of our board of directors or a committee of our board of directors. Our bylaws will prescribe specific information that the stockholder’s notice must contain, including, among other things, information about: (1) any CPG common stock, options, or related derivative instruments owned, directly or indirectly, by the stockholder giving the notice, the beneficial owner, if any, on whose behalf the nomination or proposal is made, and their respective affiliates or associates or others acting in concert therewith; (2) if applicable, the business other than a nomination desired to be brought before the meeting; and (3) if applicable, each person whom the stockholder proposes to nominate for election or reelection to our board of directors. Generally, under our bylaws, to be timely notice must be received at the principal executive offices of CPG not less than 90 days nor more than 120 days prior to the first anniversary of the preceding year’s annual meeting. Notwithstanding the specific provisions of our bylaws, stockholders may request inclusion of proposals in our proxy statement pursuant to Rule 14(a)-8 under the Exchange Act or inclusion of nominees in our proxy statement pursuant to other SEC proxy rules.

Removal of Directors. Our charter will provide that, subject to the rights of holders of any series of our preferred stock with respect to the election of directors, our stockholders may only remove a director for cause by the affirmative vote of a majority of the voting power of our capital stock.

Size of Board. Our charter will provide that the number of directors on our board of directors will be not less than seven nor more than 12, with the exact number of directors to be fixed exclusively by our board of directors, subject to the rights of holders of any series of our preferred stock with respect to the election of directors.

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No Stockholder Ability to Fill Director Vacancies. Our charter will provide that, subject to the rights of holders of any series of our preferred stock with respect to the election of directors:

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the number of directors shall be set exclusively by a resolution of the board of directors,

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a director may be removed from office by our stockholders only for cause and

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vacancies occurring on our board of directors for any reason and newly created directorships resulting from an increase in the number of directors may be filled only by vote of a majority of the remaining members of our board of directors.

Supermajority Requirements. Our charter will provide that, in addition to any other vote that may be required by law, applicable stock exchange rule or the terms of any series of preferred stock, a vote of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, is required to adopt, amend or repeal certain provisions of our charter. In addition, our bylaws will provide that certain provisions of our bylaws may only be amended by either the vote of at least a majority of our board of directors or the vote of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Delaware Anti-Takeover Statute. Our charter will not exempt CPG from the application of Section 203 of the DGCL, an anti-takeover law.

In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a business combination with an interested stockholder for a period of three years following the date on which the person became an interested stockholder, unless the business combination or the transaction in which the person became an interested stockholder is approved in a prescribed manner. Generally, a “business combination” includes a merger, asset or stock sale, or other transaction resulting in a financial benefit to the interested stockholder, and, generally, an “interested stockholder” is a person that, together with its affiliates and associates, owns 15% or more of the corporation’s voting stock.

Limitation of Liability of Directors

Our charter will limit the personal liability of directors to CPG and our stockholders for monetary damages for breach of fiduciary duty as a director to the maximum extent permitted by the DGCL. The DGCL provides that directors of a corporation will not be personally liable to the corporation or its stockholders for monetary damages for breach of their fiduciary duties as directors, except for liability:

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for any breach of the director’s duty of loyalty to the corporation or its stockholders,

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for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law,

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under Section 174 of the DGCL relating to unlawful payments of dividends or unlawful stock repurchases or redemptions, or

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for any transaction from which the director derived an improper personal benefit.

The limitation of liability does not apply to liabilities arising under the federal or state securities laws and does not affect the availability of equitable remedies, such as injunctive relief or rescission.

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Choice of Forum

Our charter will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for:

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any derivative action or proceeding brought on our behalf,

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any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders,

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any action asserting a claim against us arising pursuant to any provision of the DGCL or our charter or bylaws or

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any action asserting a claim against us pertaining to internal affairs of our corporation.

It is possible that a court of law could rule that the choice of forum provision contained in our charter is inapplicable or unenforceable if it is challenged in a proceeding or otherwise.

Indemnification of Directors and Officers

Our charter will require us to indemnify our directors and officers to the fullest extent authorized or permitted by the DGCL, as may be amended. Any amendment of this provision will not reduce our indemnification obligations relating to actions taken before the amendment.

A director’s or officer’s right to indemnification to be conferred by our charter includes the right to be paid by CPG the expenses incurred in defending or otherwise participating in any proceeding in advance of its final disposition, provided that the director presents a written undertaking to repay such amount if it is ultimately determined that the director is not entitled to be indemnified by CPG. We will not be obligated to indemnify or advance expenses of any director or officer in connection with any proceeding initiated by such person unless such proceeding was authorized by our board of directors.

We intend to obtain policies that insure our directors and officers and the directors and officers of our subsidiaries against certain liabilities they may incur in their capacity as directors and officers.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock will be Computershare Trust Company, N.A.

NYSE Listing

We have applied to have our common stock listed on the NYSE under the ticker symbol “CPGX.”

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows selected historical financial and operating data of CPG and the Predecessor and pro forma financial data of CPG for the periods and as of the dates indicated. Columbia Pipeline Group, Inc. was formed on September 26, 2014. Together with the closing of the initial public offering of the MLP, which was completed on February 11, 2015, NiSource contributed its subsidiary CEG to CPG. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows of the Predecessor.

The selected historical financial data presented as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 are derived from the audited financial statements of CPG and its Predecessor, which are included elsewhere in this Information Statement. The selected historical financial data presented as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are derived from the unaudited financial statements of CPG and its Predecessor, which are included elsewhere in this Information Statement. The selected historical financial data presented as of December 31, 2012 and for the year ended December 31, 2011 is derived from the audited financial statements of the Predecessor, which are not included elsewhere in this Information Statement. The selected historical financial data presented as of December 31, 2011 and 2010 and March 31, 2014 and for the year ended December 31, 2010 are derived from the unaudited financial statements of the Predecessor, which are not included elsewhere in this Information Statement.

The selected pro forma financial data as of March 31, 2015 and for the fiscal year ended December 31, 2014 and the three months ended March 31, 2015 are derived from our unaudited pro forma consolidated financial statements. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015 give effect to the Separation and related transactions as if they had occurred on January 1, 2014. The unaudited pro forma consolidated balance sheet as of March 31, 2015 gives effect to the Separation and related transactions as if they had occurred on March 31, 2015. The pro forma financial data give pro forma effect to:

MLP Adjustments

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An adjustment to noncontrolling interest to reflect the public’s interest in the MLP resulting from the MLP’s initial public offering as if it had occurred on January 1, 2014.

Distribution Adjustment

•

Financing Adjustments

•

The receipt of $2,721.0 million from our sale of senior unsecured notes, after estimated issuance costs totaling approximately $25.0 million and discounts totaling approximately $4.0 million. Debt issuance costs will be recorded as a deferred charge and amortized to interest expense over the respective terms of the notes. Discounts on issuance of the notes will be recorded as a reduction to the face value of the long-term debt and amortized to interest expense using the effective interest method. The following tranches of notes are outstanding:

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$500.0 million of 2.45% Senior Notes, due 2018

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•

$750.0 million of 3.30% Senior Notes, due 2020

•

$1.0 billion of 4.50% Senior Notes, due 2025

•

$500.0 million of 5.80% Senior Notes, due 2045

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The elimination of interest expense incurred on intercompany debt assumed to have been repaid.

•

The use of a portion of the proceeds from the senior unsecured note offering for a special dividend paid to NiSource in the amount of $1,450.0 million.

•

interest expense on the notes at an annual weighted average interest rate of 4.04% and a weighted average term of 11 years; and

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amortization of debt issuance costs, debt discounts and revolving credit facility issuance costs.

Other Adjustments

•

With the exception of short-term borrowings—affiliated, long-term debt—affiliated and interest expense—affiliated, upon completion of the Separation, amounts reflected in our historical consolidated and combined financial statements as affiliated will be reclassified to unaffiliated.

Following the Separation, we anticipate incurring incremental general and administrative expense as a result of being a stand-alone publicly traded company, including expenses associated with separate corporate services functions, annual and quarterly reporting, tax return preparation, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, and registrar and transfer agent fees. The unaudited pro forma consolidated financial statements do not reflect these additional stand-alone public company costs. No pro forma adjustment has been made for these expenses as an estimate of these expenses is not objectively determinable.

The following selected historical and unaudited pro forma financial data should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships and Related Party Transactions” and the financial statements and related notes included elsewhere in this Information Statement. Among other things, the historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net. Adjusted EBITDA is not calculated or presented in accordance with GAAP. We explain this measure under “—Non-GAAP Financial Measures” below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.


	Columbia Pipeline Group, Inc. Historical																					Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,															Three Months Ended March 31,						Three Months Ended March 31, 2015			Year Ended December 31, 2014
	2014			2013			2012			2011			2010			2015			2014			Three Months Ended March 31, 2015			Year Ended December 31, 2014
				*Predecessor*			*Predecessor*			*Predecessor*			*Predecessor*						*Predecessor*
	(in millions, except per share and operating data)
Statement of Operations Data:
Total operating revenues	$	1,348.0		$	1,180.5		$	1,001.3		$	1,006.5		$	950.0		$	340.0		$	345.8		$	340.0		$	1,348.0
Operating Expenses:
Operation and maintenance		628.4			509.0			375.9			378.4			329.6			118.4			137.2			146.4			751.6
Operation and maintenance— affiliated		123.2			118.6			106.7			102.1			78.7			28.0			28.5			—			—
Depreciation and amortization		118.8			107.0			99.4			130.2			130.8			32.5			29.8			32.5			118.8
(Gain)/loss on sale of assets		(34.5	)		(18.6	)		(0.6	)		0.1			(0.1	)		(5.3	)		(17.5	)		(5.3	)		(34.5	)
Property and other taxes		67.1			62.2			59.2			56.6			57.7			19.1			18.5			19.1			67.1

Total operating expenses	$	903.0		$	778.2		$	640.6		$	667.4		$	596.7		$	192.7		$	196.5		$	192.7		$	903.0

Equity Earnings in Unconsolidated Affiliates		46.6			35.9			32.2			14.6			15.0			15.4			9.8			15.4			46.6

Operating Income	$	491.6		$	438.2		$	392.9		$	353.7		$	368.3		$	162.7		$	159.1		$	162.7		$	491.6

Other Income (Deductions):
Interest expense		—			—			—			—			—			—			—			(28.0	)		(113.2	)
Interest expense—affiliated		(62.0	)		(37.9	)		(29.5	)		(29.9	)		(29.3	)		(18.3	)		(12.1	)		—			—
Other, net		8.8			17.9			2.1			2.0			2.8			4.6			1.9			4.6			8.8

Total Other Deductions		(53.2	)		(20.0	)		(27.4	)		(27.9	)		(26.5	)		(13.7	)		(10.2	)		(23.4	)		(104.4	)

Income from continuing operations before income taxes		438.4			418.2			365.5			325.8			341.8			149.0			148.9			139.3			387.2
Income Taxes		169.7			146.5			139.3			125.3			131.4			51.9			55.9			48.1			132.6

Income from Continuing Operations		268.7			271.7			226.2			200.5			210.4			97.1			93.0			91.2			254.6

Income (Loss) from discontinued operations—net of taxes		(0.6	)		9.0			(2.2	)		(4.7	)		(2.7	)		—			(0.2	)		—			(0.6	)

Net income	$	268.1		$	280.7		$	224.0		$	195.8		$	207.7		$	97.1		$	92.8		$	91.2		$	254.0
Less: Net income attributable to noncontrolling interest																	7.1						14.1			42.0

Net Income attributable to Columbia Pipeline Group, Inc.																$	90.0					$	77.1			212.0

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	Columbia Pipeline Group, Inc. Historical																					Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,															Three Months Ended March 31,						Three Months Ended March 31, 2015		Year Ended December 31, 2014
	2014			2013			2012			2011			2010			2015			2014			Three Months Ended March 31, 2015		Year Ended December 31, 2014
				*Predecessor*			*Predecessor*			*Predecessor*			*Predecessor*						*Predecessor*
	(in millions, except per share and operating data)
Basic Pro Forma Earnings per Share⁽¹⁾
Continuing operations																						$	0.24	$	0.67
Discontinued operations																						$	—	$	—
Diluted Pro Forma Earnings per Share⁽¹⁾
Continuing operations																						$	0.24	$	0.67
Discontinued operations																						$	—	$	—
Balance Sheet Data (at period end):
Total assets	$	8,157.5		$	7,281.2		$	6,640.2		$	6,166.0		$	6,009.1		$	8,970.0		$	7,435.6		$	8,397.3
Net property, plant and equipment		4,958.6			4,302.1			3,740.4			3,395.7			3,221.7			5,114.9			4,402.6			5,114.9
Long-term debt, excluding amounts due within one year		—			—			—			—			—			—			—			2,746.0
Long-term debt-affiliated, excluding amounts due within one year		1,472.8			819.8			754.7			294.7			453.4			1,848.2			991.4			—
Total liabilities		3,981.2			3,365.6			2,896.9			2,436.9			2,299.0			4,021.0			3,427.0			4,898.3
Total parent’s net equity		4,176.3			3,915.6			3,743.3			3,729.1			3,710.1			4,949.0			4,008.6			3,499.0
Statement of Cash Flow Data:
Net cash from (used for):
Operating activities	$	564.8		$	457.2		$	471.4		$	369.5		$	349.4		$	163.8		$	203.6
Investing activities		(860.1	)		(790.9	)		(452.8	)		(251.5	)		(208.0	)		(852.8	)		(163.8	)
Financing activities		295.4			333.1			(17.7	)		(118.0	)		(141.6	)		695.8			(39.9	)
Other Data:
Adjusted EBITDA	$	601.0		$	550.4		$	492.8		$	483.4		$	494.3		$	198.1		$	186.5		$	198.1	$	601.0
Less: Adjusted EBITDA attributable to non-controlling interest																$	9.7					$	16.6	$	50.3
Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.																$	188.4					$	181.5	$	550.7
Maintenance capital expenditures		143.4			132.7			209.6			220.0			149.6			21.5			21.3
Expansion capital expenditures		700.5			664.8			280.0			81.5			152.4			169.5			137.9
Operating Data⁽²⁾ :
Contracted firm capacity (MMDth/d)		13.2			12.8			13.1			13.1			11.8			15.3			14.2
Throughput (MMDth)		2,006.1			1,997.3			2,200.0			2,393.7			2,154.4			643.0			650.8
Natural gas storage capacity (MMDth)		287			287			283			282			283			287			287

(1)

(2)	Excludes equity investments.

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Non-GAAP Financial Measures

Adjusted EBITDA

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	Columbia Pipeline Group, Inc. Historical														Columbia Pipeline Group, Inc. Pro Forma
	Year Ended December 31,										Three Months Ended March 31,				Three Months Ended March 31, 2015		Year Ended December 31, 2014
	2014		2013		2012		2011		2010		2015		2014		Three Months Ended March 31, 2015		Year Ended December 31, 2014
			*Predecessor*		*Predecessor*		*Predecessor*		*Predecessor*				*Predecessor*
	(in millions)
Net Income	$	268.1	$	280.7	$	224.0	$	195.8	$	207.7	$	97.1	$	92.8	$	91.2	$	254.0
Add:
Interest expense		—		—		—		—		—		—		—		28.0		113.2
Interest expense—affiliated		62.0		37.9		29.5		29.9		29.3		18.3		12.1		—		—
Income taxes		169.7		146.5		139.3		125.3		131.4		51.9		55.9		48.1		132.6
Depreciation and amortization		118.8		107.0		99.4		130.2		130.8		32.5		29.8		32.5		118.8
Distributions of earnings received from equity investees		37.8		32.1		34.9		18.8		12.9		18.3		7.6		18.3		37.8
Less:
Other, net		8.8		17.9		2.1		2.0		2.8		4.6		1.9		4.6		8.8
Equity earnings in unconsolidated affiliates		46.6		35.9		32.2		14.6		15.0		15.4		9.8		15.4		46.6

Adjusted EBITDA	$	601.0	$	550.4	$	492.8	$	483.4	$	494.3	$	198.1	$	186.5	$	198.1	$	601.0
Less:
Adjusted EBITDA attributable to non-controlling interest												9.7				16.6		50.3

Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.											$	188.4			$	181.5	$	550.7


	Columbia Pipeline Group, Inc. Historical
	Year Ended December 31,														Three Months Ended March 31,
	2014			2013			2012			2011			2010		2015			2014
				*Predecessor*			*Predecessor*			*Predecessor*			*Predecessor*					*Predecessor*
	(in millions)
Net Cash Flows from Operating Activities	$	564.8		$	457.2		$	471.4		$	369.5		$	349.4	$	163.8		$	203.6
Interest expense—affiliated		62.0			37.9			29.5			29.9			29.3		18.3			12.1
Current taxes		27.1			(27.4	)		90.3			39.3			41.2		15.8			26.9
Other adjustments to operating cash flows		28.2			22.1			(1.4	)		(9.6	)		5.4		(3.2	)		15.4
Changes in assets and liabilities		(81.1	)		60.6			(97.0	)		54.3			69.0		3.4			(71.5	)

Adjusted EBITDA	$	601.0		$	550.4		$	492.8		$	483.4		$	494.3	$	198.1		$	186.5

Less:
Adjusted EBITDA attributable to non-controlling interest																9.7
Adjusted EBITDA attributable to Columbia Pipeline Group, Inc.		—			—			—			—			—	$	188.4

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of financial condition and results of operations should be read in conjunction with our historical financial statements and our pro forma financial statements and the accompanying notes included elsewhere in this Information Statement.

This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, without limitation, those identified below and those discussed in the section entitled “Risk Factors” included elsewhere in this Information Statement.

Separation

On September 28, 2014, NiSource announced that its board of directors had approved in principle plans to separate its natural gas pipeline and related businesses into a stand-alone publicly traded company. If completed, the Separation will result in two independent energy infrastructure companies: NiSource Inc., a fully regulated natural gas and electric utilities company, and Columbia Pipeline Group, Inc., a company focused solely on natural gas pipeline, midstream and storage activities. The Separation is expected to occur on July 1, 2015. Successful completion of the Separation could impact our business and operations in a number of positive ways, including increased focus of management and resources on our business and operations. However, the Separation could adversely impact our business by reducing potential access to financial support from NiSource or as a result of employee recruitment and retention issues, increased costs associated with our becoming a stand-alone public entity and potential limits on our business operations as a result of certain covenants we agree to make in the Tax Allocation Agreement that we expect to enter into with NiSource in connection with the Separation. Please read “Risk Factors—Risks Relating to the Separation.”

Overview

We are a growth-oriented Delaware corporation formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets.

We own approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2014, 94% of our revenue, excluding revenues generated from cost recovery under certain regulatory tracker mechanisms, which we refer to as “tracker-related revenues,” was generated under firm revenue contracts. As of December 31, 2014, these contracts had a weighted average remaining contract life of 5.0 years. We own these assets through Columbia OpCo, a partnership between our wholly owned subsidiary CEG and the MLP.

We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities. We plan that a portion of these costs will be financed through issuances of additional limited partnership interests in the MLP.

Our Subsidiary the MLP

The MLP is a fee-based, growth-oriented Delaware limited partnership formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets. The business and operations of the MLP are conducted through Columbia OpCo, a partnership between CEG and the MLP. The MLP owns the general partner of Columbia OpCo. Through our wholly owned subsidiary CEG, we own the general partner of the MLP, all of the MLP’s incentive distribution rights and all of the MLP’s subordinated units, which represent, in the aggregate, a 46.5% limited partnership interest in the MLP. The MLP completed its initial public offering on February 11, 2015, selling 53.5% of its limited partnership interests.

166

We expect that over time, the MLP will raise additional capital through issuances of additional limited partnership interests. CPG owns 100% of CEG. CEG is required to offer the MLP the right to purchase its 84.3% limited partnership interest in Columbia OpCo before it can sell that interest to anyone else. Although the MLP has the right of first offer to purchase CEG’s interest in Columbia OpCo, the MLP is not obligated to purchase any additional interest in Columbia OpCo from CEG. We expect the MLP to acquire additional interests in Columbia OpCo using debt and equity financing, and to the extent the MLP acquires additional interests in Columbia OpCo, we will have more cash available to execute our growth strategy. Additionally, the MLP has a $500 million credit facility. These additional sources of financing should assist us in funding our organic capital investment projects and third-party acquisitions as needed.

Operating Assets

Interstate Pipeline and Storage Assets. We own the following natural gas transportation and storage assets, which are regulated by the FERC:

•

Columbia Gas Transmission. We own 100% of the ownership interests in Columbia Gas Transmission, which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shale areas and other producing basins to the Midwest, mid-Atlantic and northeast regions. The system consists of approximately 11,400 miles of natural gas transmission pipeline, 89 compressor stations with 635,671 horsepower of installed capacity and approximately 3,436 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

•

Columbia Gulf. We own 100% of the ownership interests in Columbia Gulf, an interstate natural gas pipeline system with approximately 3,300 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,200 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus and Utica shale areas, Columbia Gulf has executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. As a result, once these projects are completed, the system will be able to receive Marcellus and Utica supplies, through upstream pipelines such as Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including LNG export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

•

Millennium Pipeline. We own a 47.5% ownership interest in Millennium Pipeline Company L.L.C., which transports an average of 1 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

•

Hardy Storage. We own a 50% ownership interest in Hardy Storage Company, LLC, which owns an underground natural gas storage field in the Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth and the ability to deliver 176,000 Dth/d. A third party, Piedmont Natural Gas Company, Inc., owns the remaining 50% ownership interest in Hardy Storage.

167

•

Crossroads. We own 100% of the ownership interests in Crossroads, which is a 202-mile interstate natural gas pipeline operating in Indiana and Ohio. Crossroads has multiple interconnects including: Natural Gas Pipeline Company of America, Trunkline Gas Company, Vector Pipeline and Panhandle Eastern that allow it to access mid-continent, Rocky Mountain, Gulf Coast, Permian and Canadian supplies. Crossroads accesses markets in Indiana, Illinois, Michigan and Ohio.

Gathering, Processing and Other Assets. We own the following gathering, processing and other assets:

•

Columbia Midstream. We own 100% of the ownership interests in Columbia Midstream, which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 103 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale areas.

•

Pennant. We own a 50% ownership interest in Pennant, which owns approximately 80 miles of wet gas gathering pipeline infrastructure, a gas processing facility and a NGL pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

•

CEVCO and Other. We own 100% of the ownership interests in CEVCO, which manages Columbia OpCo’s mineral rights positions in the Marcellus and Utica shale areas. CEVCO owns production rights to approximately 460,000 acres and has subleased the production rights in four storage fields and has also contributed its production rights in one other field. In addition, we own 100% of the ownership interests in CNS Microwave, which provides ancillary communication services to us and third parties.

Factors and Trends That Impact Our Business

Key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate; our customers and their requirements; and the government regulation of natural gas production, pipelines and storage. These key factors also play an important role in how we evaluate our business and how we implement our long-term strategies.

Natural Gas Supply and Demand Dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. The NYMEX natural gas futures contract reached a high of $13.58/MMBtu in July 2008, but has declined significantly from that high as a result of increased natural gas supply, due in large part to increased production of unconventional sources such as natural gas shale plays particularly in the Marcellus and Utica shale areas. To illustrate, the U.S. Energy Information Administration (“EIA”) reported dry gas production for the month of December 2008, at 1,744,458 million cubic feet. That same statistic increased to 2,303,935 million cubic feet in December 2014. Additionally, due to the longer lead times associated with pipeline infrastructure build-outs, pipeline capacity to transport natural gas out of these shale producing regions is constrained and has led to strong interest in pipeline expansions out of the region. The significant increase in supply has maintained downward pressure on the price of natural gas with the prompt month NYMEX natural gas futures price at $3.02/MMBtu as of May 15, 2015. We believe that over the short term, natural gas prices are likely to remain relatively flat until the supply overhang has been reduced by infrastructure build-outs to connect production with consuming regions and/or exportation.

Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional sources (defined by the EIA as natural gas produced from shale formations, tight gas and coal beds). While the EIA expects total domestic natural gas production to grow from approximately 24.2 Tcf in 2013 to 36.1 Tcf in 2035, it expects shale gas production to grow to 18.5 Tcf in 2035, or 51% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these shale plays at cost-advantaged per unit economics as compared to most conventional shale plays.

168

As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment. We believe our assets are well positioned to take advantage of the current drilling focus in liquids-rich regions.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, exportation off the continent via LNG, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. This displacement will continue due to lower cost of natural gas as a fuel for electric generation and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in 2010, approximately 45% of the electricity in the U.S. was generated by coal-fired power plants, and in 2013, approximately 39% of the electricity in the U.S. was generated by coal-fired power plants. In addition, the EIA’s 2014 Annual Energy Outlook projects that annual domestic consumption of natural gas will increase by approximately 16.5% from 24.9 quadrillion Btu in 2011 to 29.0 quadrillion Btu in 2025.

Growth Associated with Expansions. As production and demand for our services increase in our areas of operations, we believe that we are well-positioned to attract volumes to our systems through cost-effective capacity expansions. For example, we have recently completed or we are currently undertaking the following expansions:

•

West Side Expansion (Columbia Gulf-Bi-Directional). Under this project we invested approximately $113 million in system modifications and horsepower to provide a firm backhaul transportation path from the Leach, Kentucky interconnect with Columbia Gas Transmission to Gulf Coast markets on the Columbia Gulf system. This investment will increase capacity up to 540,000 Dth/d to transport Marcellus production originating in West Virginia. The project is supported by long-term firm contracts and was placed in service in the fourth quarter of 2014. The Alexandria Compression portion of Columbia Gulf’s West Side Expansion (approximately $75 million in capital costs) will be placed in service in the third quarter of 2015.

•

Chesapeake LNG. The project involves the investment of approximately $33 million to replace 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives. This project is expected to be placed in service in the second quarter of 2015.

•

Big Pine Expansion. We are investing approximately $65 million to make a connection to the Big Pine pipeline and add compression facilities that will add incremental capacity. The additional 9 miles of 20-inch pipeline and compression facilities will support Marcellus shale production in western Pennsylvania. Approximately 50% of the increased capacity generated by the project is supported by a long-term fee-based agreement with a regional producer, with the remaining capacity expected to be sold to other area producers in the near term. We expect the project to be placed in service in the third quarter of 2015.

•

East Side Expansion. We have received FERC authorization to construct facilities, which will provide access for production from the Marcellus shale to the northeastern and mid-Atlantic markets. Supported by long-term firm contracts, the project will add up to 312,000 Dth/d of capacity and is expected to be placed in service in the fourth quarter of 2015. We plan to invest up to approximately $275 million in this project.

•

169

•

Kentucky Power Plant Project. We expect to invest approximately $24 million to construct 2.7 miles of 16-inch greenfield pipeline and other facilities to a third-party power plant from Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service, is supported by a long-term firm contract, and will be placed in service in the second quarter of 2016.

•

Utica Access Project. We intend to invest approximately $51 million to construct 4.7 miles of 24-inch greenfield pipeline to provide 205,000 Dth/d of new firm service to allow Utica production access to liquid trading points on our system. This project is expected to be in service in the fourth quarter of 2016. We have secured firm contracts for the full delivery volume.

•

Leach XPress. We finalized agreements for the installation of approximately 124 miles of 36-inch pipeline from Majorsville to the Crawford compressor station (“Crawford CS”) located on the Columbia Gas Transmission system, and 27 miles of 36-inch pipeline from Crawford CS to the McArthur compressor station located on the Columbia Gas Transmission system, and approximately 101,700 horsepower across multiple sites to provide approximately 1.5 MMDth/d of capacity out of the Marcellus and Utica production regions to the Leach CS located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. Virtually all of the project’s capacity has been secured with long-term firm contracts. We expect the project to go in service in the fourth quarter of 2017 and will invest approximately $1.4 billion in this project.

•

Rayne XPress. This project would transport approximately 1 MMDth/d of growing southwest Marcellus and Utica production away from constrained production areas to markets and liquid transaction points. Capable of receiving gas from Columbia Gas Transmission’s Leach XPress project, gas would be transported from the Leach, Kentucky interconnect with Columbia Gas Transmission in a southerly direction towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. The project also includes the creation of a new compressor station. We have secured definitive agreements for firm service for the project’s capacity and expect the project to be placed in service in the fourth quarter of 2017. We expect to invest approximately $383 million on the Rayne XPress project to modify existing facilities and to add new compression.

•

Cameron Access Project. We are investing approximately $310 million in an 800,000 Dth/d expansion of the Columbia Gulf system through improvements to existing pipeline and compression facilities, a new state-of-the-art compressor station near Lake Arthur, Louisiana, and the installation of a new 26-mile pipeline in Cameron Parish to provide for a direct connection to the Cameron LNG Terminal. We expect the project to be placed in service in the first quarter of 2018 and have secured long-term firm contracts for approximately 90% of the increased volumes.

•

WB XPress. We expect to invest approximately $850 million in this project to expand the WB system through looping and added compression in order to transport approximately 1.3 MMDth/d of Marcellus shale production on the Columbia Gas Transmission system to pipeline interconnects and East Coast markets, which includes access to the Cove Point LNG terminal. We expect this project to be placed in service in the fourth quarter of 2018.

Finally, we and our customers have agreed to a mechanism that provides recovery and return on our initial investment of up to $1.5 billion over a five-year period, which began in 2013, to modernize our Columbia Gas Transmission system to improve system integrity and enhance service reliability and flexibility. Pursuant to the modernization settlement with the FERC, we must annually incur at least $100 million in maintenance capital expenditures in order to trigger the terms of the modernization settlement’s recovery mechanism. The modernization program includes replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

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Our Customers. Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. Our customers use our transportation services for a variety of reasons:

•

LDCs, municipal utilities, and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. These customers will typically enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract;

•

Producers of natural gas and LNG exporters require the ability to deliver their product to market and typically enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity; and

•

Marketers use our transportation services to capitalize on natural gas price volatility over time or between markets.

Impact of New Supply Basins and End-Use Markets. The Columbia Gulf pipeline system was originally constructed for the primary purpose of moving natural gas produced on the Gulf Coast north through Columbia Gas Transmission to Midwestern and mid-Atlantic end-use markets. Increases in production in the Marcellus and Utica shale areas have resulted in a shift of production supply to Northeast markets, displacing the need for production in the Gulf Coast and other Western supply sources. In the past several years, access to new supply and access to new markets have been added to the system through new interconnections and other system modifications. For example, we are currently implementing projects that will make much of the system bi-directional, increasing the flexibility of how we operate this system. As a result of the development of laterals, interconnects, and bi-directional capability, we now have access to multiple strategic natural gas supply sources, including supplies on the Gulf Coast, basins in North Texas (Barnett shale), East Texas, North Louisiana, the Marcellus and Utica shale areas, and the Appalachian Basin. Similarly, through interconnections with major interstate and intrastate pipelines, we also access large and growing markets in the northeast, Midwest, mid-Atlantic and southeast U.S., and serve industrial, commercial, electric generation and residential customers in various states within our footprint.

Increasing Competition. Our pipeline systems compete primarily with other interstate and intrastate pipelines. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, at least in particular supply or market areas where we serve, and the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term basis, our revenues are not significantly affected by variation in customers’ actual usage resulting from increased competition during the near term. Our ability to remarket the capacity as our contracts expire may be impacted by increased competition.

Regulatory Compliance. Regulation of natural gas transportation by the FERC and other federal and state regulatory agencies, including DOT has a significant impact on our business. For example, the PHMSA office of the DOT has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. The FERC regulatory policies govern the rates and services that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates PCBs at specific gas transmission facilities pursuant to the AOC and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs ceased on January 31, 2015. As of December 31, 2014, Columbia Gas Transmission has recorded $1.8 million to cover costs associated with PCB remediation related to this AOC. The cost of this PCB remediation is not expected to have a material adverse impact on our financial condition or results of operations.

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Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of natural gas and therefore throughput on our assets.

Cost Recovery Trackers and Other Similar Mechanisms. Under Section 4 of the Natural Gas Act, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect.

Due to these trackers, a significant portion of our revenues and expenses are related to the recovery of these costs. The costs that are being recovered are reflected in revenue and are offset in expenses. These costs include: third-party transportation, electric compression, environmental, and the net expense associated with certain approved operational purchases and sales of natural gas.

Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel.

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:

•

Revenues and contract mix, particularly the level of firm capacity subscribed;

•

Operating expenses; and

•

Adjusted EBITDA.

Revenue Contract Mix and Volumes. Our results are driven primarily by the volume of natural gas transportation and storage capacity under firm and interruptible contracts, the volume of natural gas that we gather and transport, and the fees assessed for such services, as well as fees derived from royalties. One of our primary financial goals is to maximize the portion of our physical transportation and storage capacity that is contracted under multi-year firm contracts in order to enhance the stability of our revenues and cash flows. We provide a significant portion of our transportation and storage services through firm contracts and derive a small portion of our revenues through interruptible service contracts. To the extent that physical capacity that is contracted by firm service customers is not being fully utilized or there is excess capacity that is not contracted for firm service, we can offer such capacity to interruptible service customers.

We manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our contracts mature at various times and in various amounts of capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. We attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. As of December 31, 2014, our firm revenue contracts had a weighted average remaining contract life of 5.0 years.

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Transmission and Storage. Firm transportation service allows the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly charge to reserve an agreed-upon amount of pipeline capacity regardless of the actual pipeline capacity used by the customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transportation customer uses the capacity it has reserved under these firm transportation contracts. Usage charges are assessed on the actual volume of natural gas transported on the transportation system. In addition, firm transportation customers are charged an overrun usage charge when the level of natural gas received for delivery from a firm transportation customer exceeds its reserved capacity.

Firm storage contracts obligate our customers to pay a fixed monthly reservation charge for the right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges for the actual quantities of natural gas injected into or withdrawn from storage.

We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices.

For the year ended December 31, 2014, approximately 94.1% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 4.0% of the transportation and storage revenues were derived from usage fees under firm contracts compared to 93.1% and 5.0%, respectively, for the year ended December 31, 2013.

Interruptible transportation and storage service is typically less than a year and is generally used by customers that either do not need firm service, have been unable to contract for firm service or require transportation volumes in excess of their contracted firm service. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. The FERC-regulated transportation and storage operators are obligated to provide interruptible services only if a shipper is willing to pay the FERC-approved tariff rate. We believe that our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transportation and storage services is our natural gas “park and loan” services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a fee based on the quantities of natural gas they store in (park), or borrow from (loan), our storage facilities.

For each of the years ended December 31, 2014 and 2013, approximately 1.9% of the transportation and storage revenues were derived from interruptible contracts.

Gathering and Processing. Our long-term, fee-based agreements provide for a fixed fee for one or more of the following midstream natural gas services: natural gas gathering, treating, conditioning, processing, compression and liquids handling. Under these agreements, which contain minimum volume commitment features, we are paid a fixed fee based on the volume of the natural gas that we gather and process. Under these agreements, our customers commit to ship a minimum annual volume of natural gas on our gathering system, or, in lieu of shipping such volumes, to pay us periodically as if that minimum amount had been shipped. If capacity is available on the pipeline or at the processing plant, a customer may exceed its minimum volume amounts and pay a fixed fee on the additional volumes. We also provide interruptible gathering and transportation service on our gathering pipelines to optimize our revenues on those systems.

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Other Assets. We own the production rights below many of Columbia Gas Transmission’s storage facilities. Some of these production rights have been subleased to producers in return for an overriding royalty interest and upfront bonus payments. Each sublease negotiation is unique and may have additional rights or options attached to the agreement such as the option to participate as a working interest owner in drilling operations. We have also contributed our production rights in another field, Brinker storage field, to Hilcorp, and participate as a 5% working interest partner with an overriding interest in the development of a broader acreage dedication.

Operating Expenses. The primary component of our operating costs and expenses that we evaluate is operations and maintenance expenses. These expenses represent the cost of operating and maintaining our plants and equipment or the cost of running the physical systems. Operations and maintenance expenses are comprised primarily of labor, materials and supplies, outside services and other expenses. Maintenance and repairs, including the cost of removal of minor items of property, are charged to expense as incurred.

We are also charged or allocated expenses from NiSource Corporate Services, a centralized service company that provides executive, financial, legal, information technology and other administrative and general services. Costs incurred for these services consist of employee compensation and benefits, outside services and other expenses. Costs are allocated using various methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures.

Adjusted EBITDA. We evaluate our business on the basis of Adjusted EBITDA. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks and others, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay dividends to our stockholders; and

•

the operating performance and return on invested capital as compared to those of other publicly traded corporations that own energy infrastructure assets, without regard to their financing methods and capital structure.

Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees, less income from unconsolidated affiliates and other, net.

Adjusted EBITDA is not a presentation made in accordance with GAAP and is defined differently by different companies in our industry. As such, the definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. For a reconciliation of Adjusted EBITDA to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Items Affecting Comparability of Our Financial Results

Our historical financial results discussed below may not be comparable to our future financial results for the following reasons:

•

Upon the Separation, we anticipate incurring incremental general and administrative expenses as a result of being a public company.

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•

Upon the Separation, amounts reflected in our historical consolidated and combined financial statements as revenue from affiliates will be reclassified to unaffiliated third-party revenue.

•

We have entered into two credit facilities—the $500 million MLP revolving credit facility, which became effective upon the closing of the initial public offering of the MLP, and the $1,500 million CPG revolving credit facility, which will become effective at the time of the Separation. In addition, on May 22, 2015, CPG sold $2,750.0 million of senior unsecured notes. Prior to the Distribution, we intend to use the proceeds from that sale to repay $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due form the money pool, between CPG and NiSource and pay a $1,450.0 million special dividend to NiSource. As a result, interest expense incurred on intercompany debt will be eliminated and replaced with interest expense on our credit facilities and our notes.

•

We own a 46.5% interest in the MLP. We control the MLP through our ownership of its general partner. Our pro forma financial statements consolidate, and our financial statements after the Separation will consolidate, all of the MLP’s financial results with ours in accordance with GAAP. Consequently, our future consolidated financial statements will include the MLP as a consolidated subsidiary, and the public’s 53.5% interest will be reflected as a non-controlling interest.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on management assumptions and currently available information. To the extent management’s underlying assumptions about or interpretations of available information prove to be incorrect, actual results could vary materially from our expected results. Please read “Risk Factors.”

Benefits from System Expansions. We expect that our results of operations will benefit from increased revenues associated with the expansion projects identified under “—Factors and Trends That Impact Our Business—Growth Associated with Expansions” above. These projects have provided our customers with increased access to new sources of supply while extending their market reach. We are also continuing to pursue expansion across our footprint that will allow for the transport of constrained natural gas production in the Marcellus and Utica producing regions to areas of demand and/or to locations for conversion to LNGs for exportation off the continent. We expect that completion of these projects will increase utilization along our pipeline system.

Growth Opportunities. We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities. Additionally, we expect the MLP to exercise its preemptive right to purchase additional limited partnership interests in Columbia OpCo in connection with its issuance of any new equity interests.

Growing Markets. Our system provides upstream supply to northeast, Midwestern and southern end-use markets where the EIA, in its 2014 Annual Energy Outlook, estimates natural gas consumption will grow by approximately 1.3%, 9.2% and 8.7% respectively, between 2015 and 2024. Moreover, growth in natural gas consumption, according to the EIA, is centered around growth in industrial and power growth sectors. The EIA expects that subset of consumption to grow in the northeast, Midwestern and southern markets by 13.6%, 5.6% and 8.0%, respectively.

Growing LNG Export Market. Domestic dry natural gas production in the U.S. is expected to outpace domestic consumption. According to the EIA, domestic dry natural gas production is estimated to grow approximately 2.3% per year, from 24.72 quadrillion Btu in 2013 to 32.57 quadrillion Btu in 2025, while growth in U.S. natural gas demand is only estimated to grow by approximately 0.8% per year, from 26.22 quadrillion Btu in 2013 to 28.97 quadrillion Btu in 2025. The net difference between supply and demand is expected, largely, to be taken off the continent by conversion to LNG. The EIA forecasts that gross natural gas exports, including LNG exports, will increase by approximately 10.0% per year from 1.73 quadrillion Btu in 2013 to 5.45 quadrillion Btu in 2025. We believe our assets provide a unique footprint from the Marcellus and Utica regions to the Gulf of Mexico where the majority of the liquefaction facilities for LNG export have been announced, putting us in a prime position to capitalize on the LNG export market.

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Results of Our Operations

The following schedule presents our historical consolidated and combined key operating and financial metrics.


	Year Ended December 31,									Three Months Ended March 31,
	2014			2013			2012			2015			2014
				*Predecessor*			*Predecessor*						*Predecessor*
	(in millions)
Operating Revenues
Transportation revenues	$	990.8		$	850.9		$	679.3		$	248.4		$	246.9
Transportation revenues—affiliated		95.7			94.1			95.9			29.0			28.6
Storage revenues		144.0			142.8			144.3			36.6			36.3
Storage revenues—affiliated		53.2			53.6			52.4			13.3			13.7
Other revenues		64.3			39.1			29.4			12.7			20.3

Total Operating Revenues		1,348.0			1,180.5			1,001.3			340.0			345.8

Operating Expenses
Operation and maintenance		628.4			509.0			375.9			118.4			137.2
Operation and maintenance—affiliated		123.2			118.6			106.7			28.0			28.5
Depreciation and amortization		118.8			107.0			99.4			32.5			29.8
Gain on sale of assets		(34.5	)		(18.6	)		(0.6	)		(5.3	)		(17.5	)
Property and other taxes		67.1			62.2			59.2			19.1			18.5

Total Operating Expenses		903.0			778.2			640.6			192.7			196.5

Equity Earnings in Unconsolidated Affiliates		46.6			35.9			32.2			15.4			9.8

Operating Income		491.6			438.2			392.9			162.7			159.1

Other Income (Deductions)
Interest expense—affiliated		(62.0	)		(37.9	)		(29.5	)		(18.3	)		(12.1	)
Other, net		8.8			17.9			2.1			4.6			1.9

Total Other Deductions, net		(53.2	)		(20.0	)		(27.4	)		(13.7	)		(10.2	)

Income from Continuing Operations before Income Taxes		438.4			418.2			365.5			149.0			148.9
Income Taxes		169.7			146.5			139.3			51.9			55.9

Income from Continuing Operations		268.7			271.7			226.2			97.1			93.0
Income/(Loss) from Discontinued Operations—net of taxes		(0.6	)		9.0			(2.2	)		—			(0.2	)

Net Income	$	268.1		$	280.7		$	224.0		$	97.1		$	92.8

Less: Net income attributable to non-controlling interest											7.1

Net income attributable to CPG		—			—			—		$	90.0			—

Throughput (MMdth)
Columbia Gas Transmission		1,379.4			1,354.3			1,305.7			497.3			465.9
Columbia Gulf		626.7			643.0			894.3			145.7			184.9

Total		2,006.1			1,997.3			2,200.0			643.0			650.8

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Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Operating Revenues. Operating revenues were $340.0 million for the first quarter of 2015, a decrease of $5.8 million from the same period in 2014. The decrease in operating revenues was primarily due to decreased revenue of $27.4 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense, and decreased mineral rights royalty revenue of $1.8 million. These decreases were partially offset by increased revenue of $29.2 million primarily from the CCRM, the West Side Expansion and Warren County projects and other new contracts.

Operating Expenses. Operating expenses were $192.7 million for the first quarter of 2015, a decrease of $3.8 million from the same period in 2014. The decrease in operating expenses was primarily due to $27.4 million of decreased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues. This decrease was partially offset by a reduction in the gain on the sale of assets of $12.2 million primarily resulting from decreased gains on conveyances of mineral interests, as well as higher employee and administrative expenses of $7.5 million, increased depreciation of $2.7 million and higher outside service costs of $1.7 million.

Equity Earnings in Unconsolidated Affiliates. Equity earnings in unconsolidated affiliates were $15.4 million for the first quarter of 2015, an increase of $5.6 million from the same period in 2014. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline and the Pennant Joint Venture going fully in-service.

Other Income (Deductions). Other income (deductions) in the first quarter of 2015 reduced income by $13.7 million compared to a reduction in income of $10.2 million in the same period in 2014. The increase in deductions was primarily due to a $6.9 million increase in interest expense resulting from an $856.8 million increase in long-term debt affiliated. This increase was partially offset by a $1.9 million increase in the equity portion of allowance for funds used during construction (“AFUDC”).

Income Taxes. The effective income tax rates were 34.8% and 37.5% for the first quarter of 2015 and 2014, respectively. The change in the overall effective tax rates between 2015 and 2014 was primarily due to the effects of tax credits, state income taxes, utility rate-making, other permanent book-to-tax differences and income following the completion of the MLP’s initial public offering that is not subject to income tax at the partnership level.

Throughput. Throughput for the Columbia Pipeline Group Operations segment totaled 643.0 MMDth for the first quarter of 2015, compared to 650.8 MMDth for the same period in 2014. The decrease of 7.8 MMDth is primarily due to lower demand at third-party interconnects in the Southeast region of the United States partially offset by increased Marcellus and Utica natural gas production in the Northeast.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Operating Revenues. Operating revenues were $1,348.0 million for 2014, an increase of $167.5 million from the same period in 2013. The increase in operating revenues was due primarily to increased revenue of $88.4 million attributable to recovery of operating costs under our regulatory tracker mechanisms, which is offset in expense, increased revenue of $54.7 million primarily from the West Side Expansion, Warren County and Big Pine projects and other new contracts. Additionally there was increased mineral rights royalty revenue of $22.6 million primarily attributable to increased third-party drilling activity.

Operating Expenses. Operating expenses were $903.0 million for 2014, an increase of $124.8 million from the same period in 2013. The increase in operating expenses was primarily due to $88.4 million of increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, increased employee and administrative expenses of $28.3 million due to higher employee costs, increased outside service

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costs of $13.3 million, higher depreciation and amortization of $11.8 million primarily due to increased capital expenditures related to projects placed in service and higher property taxes of $4.0 million. These increases were partially offset by higher gains on the sale of assets of $15.9 million resulting from higher gains on the conveyances of mineral interests of $27.2 million, offset by the sale of storage base gas in 2013 of $11.1 million. Operating expenses were further offset by lower software data conversion costs of $8.9 million.

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $46.6 million in 2014, an increase of $10.7 million compared with 2013. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline.

Other Income (Deductions). Other Income (Deductions) in 2014 reduced income by $53.2 million compared to a reduction in income of $20.0 million in 2013. The increase in deductions was primarily due to a $24.1 million increase in interest expense resulting from $768.9 million of additional borrowings on the intercompany long-term note that originated on December 9, 2013, and a $10.5 million gain from insurance proceeds in 2013. These increases were partially offset by a $4.2 million increase in the equity portion of allowance for funds used during construction.

Income Taxes. The effective income tax rates were 38.7% and 35.0% in 2014 and 2013, respectively. The change in the overall effective tax rates between 2014 and 2013 were due primarily to AFUDC equity and consolidated state income tax benefits.

Income/(Loss) from Discontinued Operations—Net of Taxes. Income/(Loss) from Discontinued Operations—net of taxes reduced income by $0.6 million in 2014 compared to an increase in income of $9.0 million in 2013 due to a settlement at CPG’s former exploration and production subsidiary in the prior period.

Throughput. Throughput for CPG totaled 2,006.1 MMDth for 2014, compared to 1,997.3 MMDth for the same period in 2013. This increase is primarily due to colder weather experienced during early 2014 throughout much of our system.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Operating Revenues. Operating revenues were $1,180.5 million for 2013, an increase of $179.2 million from the same period in 2012, primarily due to increased revenue of $119.5 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in expense, the 2013 impact of the 2012 modernization settlement at Columbia Gas Transmission, which resulted in an increase in operating revenues of $50.3 million, higher revenue of $11.9 million from interim capacity on the West Side Expansion and increased mineral rights royalty revenue of $2.7 million. These increases were partially offset by lower shorter term transportation services of $7.6 million.

Operating Expenses. Operating expenses were $778.2 million for 2013, an increase of $137.6 million from the comparable period in 2012. The increase in operating expenses was primarily due to increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, of $119.5 million, higher employee and administrative expenses of $19.0 million that included $8.5 million related to higher pension costs, software data conversion costs of $8.9 million and higher depreciation and amortization of $7.6 million primarily due to increased capital expenditures related to projects placed in service. These increases were partially offset by higher gains on the sale of assets of $18.0 million resulting from the sale of storage base gas and conveyances of mineral interests.

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $35.9 million in 2013, an increase of $3.7 million compared with 2012. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline.

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Other Income (Deductions). Other Income (Deductions) in 2013 reduced income by $20.0 million compared to a reduction in income of $27.4 million in 2012. The decrease is primarily due to a $10.5 million gain from insurance proceeds and a $5.4 million increase in the equity portion of allowance for funds used during construction. This decrease was offset by an increase in interest expense of $8.4 million as a result of the issuance of intercompany long-term notes of $310 million in November 2012, $150 million in December 2012 and $65.1 million in December 2013.

Income Taxes. The effective income tax rate for the year ended December 31, 2013 was 35.0%, a decrease of 3.1% from the prior period. This decrease was primarily attributable to state tax benefits due to corporate restructuring.

Income/(Loss) from Discontinued Operations—Net of Taxes. Income/(Loss) from Discontinued Operations—net of taxes increased income by $9.0 million in 2013 compared to a decrease in income of $2.2 million in 2012 due to a settlement at CPG’s former exploration and production subsidiary.

Throughput. Throughput totaled 1,997.3 MMDth for 2013, compared to 2,200.0 MMDth for the same period in 2012. The colder weather, which primarily drove the increase on the Columbia Gas Transmission system, was more than offset by the impact from increased production of Appalachian shale gas that resulted in fewer deliveries being made by Columbia Gulf to Columbia Gas Transmission at Leach, Kentucky.

Liquidity and Capital Resources

Our principal liquidity requirements are to finance our operations, fund capital expenditures, satisfy our indebtedness obligations and pay dividends to our stockholders, as deemed appropriate. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future. Historically, our sources of liquidity have included cash generated from operations and intercompany loans from NiSource Finance Corp., a wholly owned subsidiary of NiSource (“NiSource Finance”). We have also historically participated in NiSource’s money pool administered by NiSource Corporate Services, whereby on a daily basis cash balances residing in our bank accounts have been swept into a NiSource corporate account. Therefore, our historical financial statements reflect little or no cash balances.

On May 22, 2015, CPG sold $2,750.0 million of senior unsecured notes. Prior to the Distribution, we intend to use the net proceeds from that sale to repay $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource and pay a $1,450.0 million special dividend to NiSource. We intend to use the remaining net proceeds for our general corporate purposes. The purpose of the special dividend is to create an appropriate debt-to-capital ratio at each of NiSource and CPG, such that each company is positioned to receive an investment grade credit rating.

Following the Separation, we expect our sources of liquidity to include:

•

cash generated from our operations;

•

$1,500 million available for borrowing under the CPG credit facility;

•

$500 million available for borrowing under the MLP credit facility;

•

debt offerings; and

•

MLP equity offerings.

We believe that cash on hand, cash generated from operations and availability under our credit facilities will be adequate to meet our operating needs, our planned short-term debt service requirements and anticipated dividends to our stockholders. We believe that future internal growth projects will be funded primarily through borrowings under our credit facilities or through issuances of debt and equity securities.

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Substantially all of our cash will be generated from cash distributions from Columbia OpCo. Columbia OpCo will be a restricted subsidiary and a guarantor under our credit facilities. Prior to the Separation, we expect to issue a significant amount of new senior indebtedness. At our request, Columbia OpCo will guarantee our future indebtedness. To the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant restrictions on its operations which, in turn, may limit its ability to finance future business opportunities and make cash distributions. Please read “Risk Factors—Risks Relating to Our Business—Columbia OpCo is a restricted subsidiary and a guarantor under our credit facilities and, if requested by us, will guarantee our future indebtedness. In addition, CPG is a guarantor under the MLP’s credit facility. Such indebtedness could limit Columbia OpCo’s and CPG’s ability to take certain actions, including incurring additional indebtedness, making acquisitions and capital expenditures and, in the case of Columbia OpCo, making distributions to CPG, which could adversely affect our business, financial condition, results of operations, ability to pay dividends to our stockholders and the value of our common stock.”

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

Changes in the terms of our transportation arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

Cash Flow. Net cash from operating activities, net cash used for investing activities and net cash from (used for) financing activities for the years ended December 31, 2014, 2013 and 2012, and the three months ended March 31, 2015 and 2014 were as follows:


	Years Ended December 31,									Three Months Ended March 31,
	2014			2013			2012			2015	2014
				*Predecessor*			*Predecessor*				*Predecessor*
	(in millions)
Net cash from operating activities	$	564.8		$	457.2		$	471.4		$163.8	$203.6
Net cash used for investing activities		(860.1	)		(790.9	)		(452.8	)	(852.8)	(163.8)
Net cash from (used for) financing activities		295.4			333.1			(17.7	)	695.8	(39.9)

Operating Activities

Net cash from operating activities for the three months ended March 31, 2015 was $163.8 million, a decrease of $39.8 million compared to the three months ended March 31, 2014. The decrease in net cash from operating activities was primarily attributable to a decrease in customer deposits related to growth projects of $75.6 million.

Net cash from operating activities for the year ended December 31, 2014 was $564.8 million, an increase of $107.6 million from a year ago. The increase in net cash from operating activities was primarily due to an increase in customer deposits related to growth projects of $75.6 million partially offset by a decrease in working capital from income tax receivables of $27.4 million primarily due to a refund from the IRS received in 2013.

Net cash from operating activities for the year ended December 31, 2013 was $457.2 million, a decrease of $14.2 million from a year ago. The decrease in net cash from operating activities was primarily due to a decrease in working capital due to changes in the funded status of the postretirement and postemployment benefits obligation partially offset by an increase in working capital from income tax receivables of $27.4 million primarily due to a refund from the IRS received in 2013.

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Investing Activities

The table below reflects actual expansion and maintenance capital expenditures and other investing activities for years ended December 31, 2014, 2013 and 2012 and estimates for 2015, and the three months ended March 31, 2015 and 2014.


	Years Ended December 31,								Three Months Ended March 31,
	2015E		2014		2013		2012		2015		2014
					*Predecessor*		*Predecessor*				*Predecessor*
	(in millions)
Expansion-modernization, system growth, and equity investments	$	912.2	$	700.5	$	664.8	$	280.0	$	169.5	$	137.9
Maintenance		146.5		143.4		132.7		209.6		21.5		21.3

Total⁽¹⁾	$	1,058.7	$	843.9	$	797.5	$	489.6	$	191.0	$	159.2

(1)

The difference between total capital expenditures in this table and the capital expenditures line item on our statement of cash flows primarily consists of (i) contributions to equity investees, (ii) the non-cash change in capital expenditures included in current liabilities, (iii) the non-cash change in working interest payable and (iv) non-cash AFUDC equity.

Capital expenditures for the three months ended March 31, 2015 were $191.0 million, compared to $159.2 million for the comparable period in 2014. This increased spending is mainly due to higher spending on various growth projects primarily in the Marcellus and Utica shale areas and for expenditures under the modernization program.

Capital expenditures in 2014 were higher than 2013 by $46.4 million due to system growth in the Marcellus and Utica shale areas. Capital expenditures in 2013 increased by $307.9 million compared to 2012 due to the modernization program and system growth and equity investments in the Marcellus and Utica shale areas.

The capital expenditure program and other investing activities in 2015 are projected to be approximately $1,058.7 million. The projected 2015 expenditures are comprised of (i) a current profile of identified growth projects and (ii) modernization and maintenance capital expenditures.

Financing Activities

Net cash from financing activities for the three months ended March 31, 2015 were $695.8 million, an increase of $735.7 million compared to the three months ended March 31, 2014. The increase in net cash from financing activities was primarily due to net proceeds from the initial public offering of the MLP of $1,168.4 million, partially offset by the $500.0 million return of pre-formation capital expenditures to NiSource.

Net cash from financing activities for the year ended December 31, 2014 was $295.4 million, a decrease of $37.7 million from a year ago. The decrease in net cash from financing activities was due to a decrease in short-term borrowings from the money pool to fund capital expenditures. These decreases were partially offset by a decrease in dividends to parent paid in the prior year and additional borrowings on the intercompany long-term note that originated on December 9, 2013.

Net cash from financing activities for the year ended December 31, 2013 was $333.1 million, an increase of $350.8 million from the prior year. The increase in net cash from financing activities was due to an increase in short-term borrowings from the money pool to fund capital expenditures.

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Description of Senior Unsecured Notes

On May 22, 2015, we sold $2,750.0 million of senior unsecured notes. The $2,750 of senior unsecured notes are comprised of $500 million of 2.45% senior notes due 2018 (the “2018 Notes”), $750 million of 3.30% senior notes due 2020 (the “2020 Notes”), $1,000 million of 4.50% senior notes due 2025 (the “2025 Notes”) and $500 million of 5.80% senior notes due 2045 (the “2045 Notes” and, together with the 2018 Notes, 2020 Notes and 2025 Notes, the “Notes”). The Notes are expected to be issued at a discount, for net proceeds of approximately $2.721 billion after deducting the initial purchasers’ discount and estimated offering expenses.

Indenture

The Notes are governed by an Indenture, dated as of May 22, 2015 (the “Indenture”), by and among CPG and the Guarantors named in the Indenture (the “Guarantors”) with U.S. Bank National Association, as trustee (the “Trustee”).

The initial Guarantors are three wholly-owned subsidiaries of CPG: CEG, Columbia OpCo and OpCo GP. The Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all of the Guarantors. Each guarantee of CPG’s obligations under the Notes is a direct, unsecured and unsubordinated obligation of the Guarantor and has the same ranking with respect to indebtedness of that Guarantor as the Notes have with respect to CPG’s indebtedness.

The Notes and the guarantees are (a) unsecured, (b) effectively junior in right of payment to any future secured indebtedness of CPG and the Guarantors, (c) equal in right of payment with any existing and future unsubordinated indebtedness of CPG and the Guarantors and (d) senior in right of payment to any future subordinated indebtedness of CPG and the Guarantors.

The Indenture contains covenants that, among other things, limit the ability of CPG and certain of its subsidiaries to incur liens, to enter into sale and lease-back transactions and to enter into mergers, consolidations or transfers of all or substantially all of their assets. The Indenture also contains customary events of default.

The 2018 Notes will mature on June 1, 2018, the 2020 Notes will mature on June 1, 2020, the 2025 Notes will mature on June 1, 2025 and the 2045 Notes will mature on June 1, 2045. Interest on the Notes of each series will be payable semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2015.

If the Separation is not completed on or prior to October 2, 2015, CPG will be required to redeem all of the Notes of each series at a redemption price equal to 101% of the principal amount of the Notes to be redeemed (the “Mandatory Redemption Price”) plus accrued and unpaid interest to the redemption date. CPG may also redeem all of the Notes of each series at its option at the Mandatory Redemption Price plus accrued and unpaid interest to the redemption date if, prior to October 2, 2015, CPG determines in its sole discretion that the Distribution will not occur on or prior to that date.

Upon the occurrence of certain Change of Control Triggering Events (as defined in the Indenture), each holder of the Notes will have the right to require that CPG purchase all or a portion of such holder’s Notes of such series at a purchase price in cash equal to 101% of the principal amount thereof plus any accrued and unpaid interest, if any, to, but not including, the date of purchase.

Registration Rights Agreement

In connection with the private placement of the Notes, CPG and the Guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Initial Purchasers named in the Registration Rights Agreement, pursuant to which CPG and the Guarantors agreed to file, and use their reasonable best efforts

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to cause to become effective, an exchange offer registration statement with the SEC and to consummate an exchange offer within 360 days after the date of issuance of the Notes pursuant to which holders of each series of the Notes can exchange the Notes issued in the offering for registered notes having the same terms as the Notes. Under certain circumstances set forth in the Registration Rights Agreement, in lieu of a registered exchange offer, CPG and the Guarantors must file, and use reasonable best efforts to cause to become effective, a shelf registration statement for the resale of the Notes. If CPG fails to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 0.50% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Description of Credit Agreements. We are party to two credit agreements: the CPG revolving credit facility and the MLP revolving credit facility.

CPG Credit Facility. CPG has entered into a $1,500 million senior revolving credit facility that will become effective as of the Separation. CPG expects that $750 million of this facility will be utilized as credit support for Columbia OpCo and its subsidiaries and that the remaining $750 million of this facility will be available for CPG’s general corporate purposes, including working capital.

We expect that CPG’s obligations under the CPG revolving credit facility will be unsecured. However, if CPG’s credit rating at the time of the Separation is not BB+ or better and Ba1 or better, then we may be required to post collateral to secure our obligations. Loans under the CPG revolving credit facility will bear interest at CPG’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.50 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. CPG’s revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to CPG’s credit rating.

Revolving indebtedness under the CPG credit facility will rank equally with all of CPG’s outstanding unsecured and unsubordinated debt. CEG, CPG Opco GP LLC and Columbia OpCo have each fully guaranteed the CPG credit facility. The CPG revolving credit facility contains various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. The CPG revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50 million.

The CPG revolving credit facility also contains certain negative financial covenants that will require CPG (a) to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for any period of four consecutive fiscal quarters (each, a “test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017, and during a Specified Acquisition Period (as defined in the CPG revolving credit facility), the leverage ratio may not exceed 5.50 to 1.00 and (b) until CPG has received an investment grade credit rating, to maintain a Consolidated Interest Coverage Ratio (as defined in the CPG revolving credit facility) of no less than 3.00 to 1.00.

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A breach by CPG of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against CPG or any guarantor.

MLP Credit Agreement. The MLP has a $500 million senior revolving credit facility, of which $50 million is available for the issuance of letters of credit. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls.

The MLP’s obligations under the MLP revolving credit facility are unsecured. However, if the credit rating of CPG at the time of the Separation is not BB+ or better and Ba1 or better, then we may be required to post collateral to secure the MLP’s obligations. Loans under the MLP revolving credit facility will bear interest at the MLP’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.50 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the MLP revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP revolving credit facility, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the MLP revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP revolving credit facility. The MLP revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the MLP revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP revolving credit facility.

The revolving indebtedness under the MLP credit facility ranks equally with all of the MLP’s outstanding unsecured and unsubordinated debt. NiSource, CEG, CPG Opco GP LLC, CPG and Columbia OpCo have each fully guaranteed the MLP credit facility, except that NiSource will be released from its guarantee upon receipt by CPG of a rating by Moody’s and S&P.

The MLP revolving credit agreement contains various covenants and restrictive provisions which, among other things, limit the MLP’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by the MLP’s organizational documents. The restricted payment provision does not prohibit the MLP or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the MLP revolving credit agreement), and neither the MLP nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. If the MLP fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The MLP revolving credit agreement also contains customary events of default, including cross default provisions that apply to any other indebtedness the MLP may have with an outstanding principal amount in excess of $50 million.

The MLP revolving credit agreement also contains certain negative financial covenants that will require the MLP (a) to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the test period ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the MLP revolving credit agreement), then the leverage ratio may not exceed 5.50 to 1.00 and (b) until CPG has received an investment grade credit rating, to maintain a Consolidated Interest Coverage Ratio (as defined in the MLP revolving credit agreement) of no less than 3.00 to 1.00.

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A breach by the MLP of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against the MLP or any guarantor.

Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt-affiliated, lease obligations and service obligations for pipeline service agreements. The total contractual obligations in existence at December 31, 2014 and their maturities were:


	Total		2015		2016		2017		2018		2019		After
	(in millions)
Long-term debt-affiliated⁽¹⁾	$	1,588.7	$	115.9	$	879.3	$	—	$	—	$	—	$	593.5
Interest payments on long-term debt		781.4		79.5		73.5		31.7		31.7		31.7		533.3
Pipeline transportation capacity agreements		224.7		42.7		42.0		38.6		25.9		19.2		56.3
Operating leases⁽²⁾		49.6		4.7		3.4		5.8		5.5		5.3		24.9

Total contractual obligations	$	2,644.4	$	242.8	$	998.2	$	76.1	$	63.1	$	56.2	$	1,208.0

(1)	Includes current portion of long-term debt-affiliated

(2)

Operating lease expense was $14.9 million in 2014, $13.3 million in 2013 and $10.7 million in 2012, which includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.

Our long-term financing requirements have historically been satisfied through borrowings from NiSource Finance.

We have third-party transportation agreements that provide for transportation and storage services. These agreements, which have expiration dates ranging from 2015 to 2025, require us to pay fixed monthly charges and allow us to use third-party transportation as operationally needed. Most of these costs are eligible to be collected through a FERC-approved regulatory tracker from our shippers.

We continued to borrow on the intercompany long-term note that originated on December 9, 2013, while also repaying previous borrowings and assuming new intercompany long-term notes that originated on February 4, 2015 in the three months ended March 31, 2015. The following table summarizes the maturity of long-term debt—affiliated at March 31, 2015:


	Total		2015		2016		2017		2018		2019		After
	(in millions)
Long-term debt-affiliated	$	1,848.2	$	—	$	630.9	$	—	$	—	$	—	$	1,217.3
Interest payments on long-term debt		997.6		74.8		74.8		44.8		44.8		44.8		713.6

Total contractual obligations	$	2,845.8	$	74.8	$	705.7	$	44.8	$	44.8	$	44.8	$	1,930.9

There were no material changes during the three months ended March 31, 2015 to CPG’s pipeline transportation capacity agreements and operating lease contractual obligations as of December 31, 2014.

Critical Accounting Policies

We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on results of operations and the consolidated balance sheet.

Basis of Accounting for Rate-Regulated Subsidiaries. Accounting Standards Codification (“ASC”) Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it

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probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were $158.0 million and $297.0 million at December 31, 2014, and $142.6 million and $284.7 million at December 31, 2013, respectively. For further discussion, please see Note 8, “Regulatory Matters,” in the Company’s audited Notes to Consolidated and Combined Financial Statements.

In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If we are unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated companies will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.

No regulatory assets were earning a return on investment at December 31, 2014. As of December 31, 2014, regulatory assets of $23.9 million were covered by specific regulatory orders and were being recovered as components of cost of service over a remaining life up to 25 years.

Pensions and Postretirement Benefits. NiSource has historically provided defined benefit plans for both pensions and other postretirement benefits that cover our employees. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of NiSource’s pensions and other postretirement benefits, please see Note 11, “Pension and Other Postretirement Benefits,” in the Company’s audited Notes to Consolidated and Combined Financial Statements.

Goodwill. In accordance with the provisions for goodwill accounting under GAAP, we test our goodwill for impairment annually as of May 1 each year unless indicators, events or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB. Columbia Gas Transmission Operations has been determined to be a reporting unit. Our goodwill assets at December 31, 2014 and 2013 were $1,975.5 million pertaining to the acquisition of CEG on November 1, 2000.

We completed a quantitative (“step 1”) fair value measurement of our reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed under the step 1 annual impairment test. For 2013 and 2014, a qualitative (“step 0”) test was performed as of May 1 of each respective period. We assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units in its baseline May 1, 2012 test. The results of this assessment indicated that it is not more likely than not that its reporting unit fair values are less than the reporting unit carrying values and no impairments are necessary.

Although there was no goodwill asset impairment as of May 1, 2014, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward-looking in nature, or if our market capitalization stays below book value for an extended period of time. No impairment triggers were identified subsequent to May 1, 2014.

Please see Notes 1-I and 6, “Goodwill” in the Company’s audited Notes to Consolidated and Combined Financial Statements for further discussion.

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Revenue Recognition. Revenue is recognized as services are performed. Revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.

The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.

We provide shorter term transportation services, for which cash is received at inception of the service period and is recorded as deferred revenue and recognized as income over the period the services are provided.

Revenues from storage are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

Our subsidiary CEVCO owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $43.8 million, $21.2 million and $18.5 million for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in “Other revenues” on the Statements of Consolidated and Combined Operations.

We periodically recognize gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop or produce oil or gas from a particular property or group of properties. The gains are initially deferred if we have a substantial obligation for future performance. As the obligation for future performance is satisfied the deferred revenue is relieved and the associated gain is recognized. Gains on the conveyance of mineral interest were $34.5 million, $7.3 million and zero for the years ended December 31, 2014, 2013 and 2012, respectively, and are included in “Gain on sale of assets” on the Statements of Consolidated and Combined Operations.

There were no material changes during the three months ended March 31, 2015 to CPG’s critical accounting policies as of December 31, 2014.

Recently Issued Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-05, Intangibles—Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement. ASU 2015-05 clarifies guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. We will be required to adopt ASU 2015-05 for periods beginning after December 15, 2015, including interim periods, and the guidance is permitted to be applied either (1) prospectively to all agreements entered into or materially modified after the effective date, or (2) retrospectively, with early adoption permitted. We are currently evaluating the impact the adoption of ASU 2015-05 will have on the Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. We will be required to adopt ASU 2015-03 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively with early adoption permitted. We are currently evaluating the impact the adoption of ASU 2015-03 will have on the Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

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In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. We will be required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. We are currently evaluating the impact the adoption of ASU 2015-02 will have on our Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

Qualitative and Quantitative Disclosures About Market Risk

Risk is an inherent part of our business. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal risks that are involved in our businesses: commodity market risk, interest rate risk and credit risk. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These include but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of our business, our risk management processes, policies and procedures continue to evolve and are subject to ongoing review and modification.

Commodity Price Risk. Other than the base gas purchased and used in the natural gas storage facilities, which is necessary to maintain pressure and deliverability in the storage pools, we generally do not take title to the natural gas that we store and/or transport for customers and, accordingly, we are not exposed to commodity price fluctuations on natural gas stored in our facilities or transported through our pipelines by our customers. Base gas purchased and used in natural gas storage facilities is considered a long-term asset and is not re-valued at current market prices. A certain amount of gas is naturally lost in connection with transporting natural gas across our pipeline system and, under our contractual arrangements with our customers, we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as our fuel usage. Except for the base gas in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to the volumes of fuel we purchase to make up for line loss, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas over the intermediate term should not materially impact our operations. We have not historically engaged in material commodity hedging activities relating to our assets. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.

Interest Rate Risk. We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our intercompany term loans, which have fixed and variable interest rates. We entered into a variable interest term loan with NiSource Finance, which carries an interest rate of prime plus 150 basis points. As of March 31, 2015, the outstanding balance on this term loan was $630.9 million. An increase or decrease of 100 basis points in interest rate would result in $6.3 million change in annual interest expense with respect to this loan. We monitor market debt rates to identify the need to mitigate this risk.

Credit Risk. Due to the nature of the industry, credit risk is embedded in our business activities. Our extension of credit is governed by NiSource’s Corporate Credit Risk Policy, and post-Separation we expect to have a similar policy. In addition, NiSource’s Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by NiSource’s Corporate Credit Risk function, which is independent of operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. Exposure to credit risk is measured in terms of current obligations net of any posted collateral such as cash, letters of credit and qualified guarantees of support.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

188

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC with respect to the shares of our common stock that NiSource stockholders will receive in the Distribution. This Information Statement is a part of that registration statement and, as allowed by SEC rules, does not include all of the information you can find in the registration statement or the exhibits to the registration statement. For additional information relating to CPG and the Separation, reference is made to the registration statement and the exhibits to the registration statement. While we have provided a summary of the material terms of certain agreements and other documents, the summary does not describe all of the details of the agreements and other documents. If an agreement or other document is filed as an exhibit to the registration statement, please refer to the registration statement. Each such statement in this registration statement regarding an agreement or other document is qualified in all respects by reference to the applicable exhibit.

Upon effectiveness of our registration statement of which this Information Statement forms a part, we will become subject to the information and periodic reporting requirements of the Exchange Act and will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to furnish our stockholders with annual reports containing consolidated financial statements audited by an independent registered public accounting firm. The registration statement is, and any of these future filings with the SEC will be, available to the public over the Internet on the SEC’s website at http://www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room at 100 F Street, NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

You may request copies of our filings, at no cost other than for exhibits of such filings, by writing to or telephoning us at the following address and telephone number (or by visiting our web site at www.columbiapipelinegroup.com):

Columbia Pipeline Group, Inc.

Office of the Secretary

5151 San Felipe Street

Suite 2500 Houston, Texas 77056

Telephone number: (713) 386-3701

HOUSEHOLDING

If you and other residents at your mailing address own shares of NiSource common stock in street name, your broker, bank or other nominee may have sent you a notice that your household will receive only one Annual Report and Proxy Statement for each company in which you hold stock through that broker or bank. This practice, known as “householding,” is designed to reduce printing and postage costs. If you did not respond that you did not want to participate in householding, the broker, bank or other nominee will assume that you have consented and will send only one copy of this Information Statement to your address. You may revoke your consent to householding at any time by sending your name, the name of your broker, bank or other nominee and your account number to Broadridge, Householding Department, 51 Mercedes Way, Edgewood, New York 11717. The revocation of your consent to householding will be effective 30 days following its receipt. In any event, if you did not receive an individual copy of this Information Statement, or if you wish to receive individual copies of our proxy statements and annual reports in the future, we will send a copy to you if you call (713) 386-3701, or write to Columbia Pipeline Group, Inc., Attn: Corporate Secretary, 5151 San Felipe St., Suite 2500, Houston, Texas 77056.

If you and other residents at your mailing address are registered stockholders and you receive more than one copy of this Information Statement, but you wish to receive only one copy, you must request, in writing, that we and NiSource eliminate these duplicate mailings. To request the elimination of duplicate copies, please write to Computershare, P.O. Box 30170, College Station, Texas 77842-3170.

189

INDEX TO FINANCIAL STATEMENTS


Columbia Pipeline Group, Inc.
Unaudited Pro Forma Consolidated Financial Statements
Introduction			F-2
Pro Forma Consolidated Balance Sheet as of March 31, 2015			F-4
Pro Forma Statement of Consolidated Operations for the Year Ended December 31, 2014			F-6
Pro Forma Statement of Consolidated Operations for the Three Months Ended March 31, 2015			F-7
Notes to Unaudited Pro Forma Consolidated Financial Statements			F-8

Columbia Pipeline Group, Inc.
Unaudited Interim Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014			F-10
Condensed Statements of Consolidated and Combined Operations for the Three Months Ended March 31, 2015 and 2014			F-12
Condensed Statements of Consolidated and Combined Comprehensive Income for the Three Months Ended March 31, 2015 and 2014			F-13
Condensed Statements of Consolidated and Combined Cash Flows for the Three Months Ended March 31, 2015 and 2014			F-14
Condensed Statements of Consolidated Equity for the Three Months Ended March 31, 2015			F-15
Notes to Condensed Consolidated and Combined Financial Statements			F-16
Audited Historical Financial Statements
Report of Independent Registered Public Accounting Firm			F-28
Consolidated and Combined Balance Sheets as of December 31, 2014 and 2013			F-29
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2014, 2013 and 2012			F-31
Statements of Consolidated and Combined Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012			F-32
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			F-33
Statements of Consolidated and Combined Parent Net Equity for the Years Ended December 31, 2014, 2013 and 2012			F-34
Notes to Consolidated and Combined Financial Statements			F-35

Columbia Pipeline Group, Inc.

Unaudited Pro Forma Consolidated Financial Statements

for the Year Ended December 31, 2014 and the Three Months Ended March 31, 2015

Introduction—On September 26, 2014, the board of directors of NiSource Inc. (“NiSource”) approved in principle plans to separate NiSource’s natural gas pipeline and related businesses through a pro rata distribution (the “Distribution”) to NiSource stockholders of all of the outstanding common stock of Columbia Pipeline Group, Inc. (“CPG”). This separation (the “Separation”) is expected to take place on July 1, 2015, subject to the satisfaction of various conditions. Following the Separation, CPG will be an independent, publicly traded company, and NiSource will not retain any ownership interest in CPG. The following steps are being taken in connection with the Separation:

•

CPG issued $2,750.0 million of debt securities and received approximately $2,721.0 million of cash. Prior to the Distribution, CPG expects to use the proceeds to repay $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource and make a cash distribution of $1,450.0 million to NiSource.

•

All of the shares of CPG common stock will be distributed to NiSource’s stockholders on a pro rata basis.

Together with the closing of the initial public offering of Columbia Pipeline Partners LP (the “MLP”), which was completed on February 11, 2015, NiSource contributed its subsidiary Columbia Energy Group (“CEG”) to CPG. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of NiSource. CEG owns the general partner of the MLP and all of the MLP’s subordinated limited partnership units and incentive distribution rights. CPG did not have any material assets or liabilities as a separate corporate entity until the contribution from NiSource on February 11, 2015. This contribution was recorded at historical cost as the reorganization is among entities under common control. Following the distribution of CPG shares to NiSource stockholders, CPG will be an independent company focused solely on natural gas pipeline, midstream and storage activities.

Unaudited pro forma financial information—The following unaudited pro forma consolidated financial statements should be read in conjunction with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the unaudited condensed consolidated and combined financial statements and accompanying notes and the audited historical consolidated and combined financial statements and accompanying notes included elsewhere within this Information Statement.

The unaudited pro forma consolidated financial statements are derived from the financial statements of CPG, included elsewhere in this Information Statement. CPG primarily consists of the business attributable to NiSource’s Columbia Pipeline Group Operations reportable segment, which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource. The pro forma adjustments to the consolidated statements of operations for the three months ended March 31, 2015 and the year ended December 31, 2014 give effect to the Separation and related transactions as if they had occurred on January 1, 2014, the beginning of the most recent fiscal year for which audited financial statements are available. Pro forma adjustments to the consolidated balance sheet as of March 31, 2015 give effect to the Separation and related transactions as if they had occurred on March 31, 2015.

The unaudited pro forma consolidated financial statements are for illustrative and informational purposes only and are not intended to represent what our results of operations or financial position would have been had the Separation and the Distribution occurred on the dates indicated. The unaudited pro forma consolidated financial statements also should not be considered indicative of our future results of operations or financial position as an independent, publicly traded company. See “Cautionary Note Concerning Forward-Looking Statements” included in this Information Statement.

F-2

The following unaudited pro forma statements of consolidated operations and unaudited pro forma consolidated balance sheet give pro forma effect to the following:

•

MLP Adjustments—reflect the adjustment to noncontrolling interest to reflect the initial public offering of the MLP;

•

Distribution Adjustments—reflect the issuance of shares of CPG common stock so that shares issued equals the number of shares of NiSource common stock;

•

Financing Adjustments—reflect the receipt of cash from our offering of debt securities with a corresponding adjustment to interest expense and a cash distribution to NiSource from the net proceeds of our debt securities offering; and

•

Other Adjustments—reflect certain other adjustments to give effect to the Separation.

F-3

Columbia Pipeline Group, Inc.

Unaudited Pro Forma Consolidated Balance Sheet


	As of March 31, 2015
	CPG Historical			Pro Forma Adjustments			Pro Forma
				(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	7.3		$	2,721.0	(c)	$	253.1
					(1,025.2	)(d)
					(1,450.0	)(f)
Accounts receivable (less reserve of $0.6)		125.3			19.5	(i)		144.8
Accounts receivable-affiliated		863.0			(19.5	)(i)		—
					(843.5	)(d)
Materials and supplies, at average cost		25.2			—			25.2
Exchange gas receivable		28.2			—			28.2
Regulatory assets		7.7			—			7.7
Deferred property taxes		47.8			—			47.8
Deferred income taxes		49.2			—			49.2
Prepayments and other		13.0			—			13.0

Total Current Assets		1,166.7			(597.7	)		569.0

Investments
Unconsolidated affiliates		440.3			—			440.3
Other investments		2.6			—			2.6

Total Investments		442.9			—			442.9

Property, Plant and Equipment
Property, plant and equipment		8,121.6			—			8,121.6
Accumulated depreciation and amortization		(3,006.7	)		—			(3,006.7	)

Net Property, Plant and Equipment		5,114.9			—			5,114.9

Other Noncurrent Assets
Regulatory assets		148.4			—			148.4
Goodwill		1,975.5			—			1,975.5
Postretirement and postemployment benefits assets		106.2			—			106.2
Deferred charges and other		15.4			25.0	(c)		40.4

Total Other Noncurrent Assets		2,245.5			25.0			2,270.5

Total Assets	$	8,970.0		$	(572.7	)	$	8,397.3

The accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements are an integral part of these statements.

F-4


	As of March 31, 2015
	CPG Historical			Pro Forma Adjustments			Pro Forma
				(in millions)
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings-affiliated	$	20.5		$	(20.5	)(d)	$	—
Accounts payable		44.2			45.3	(i)		89.5
Accounts payable-affiliated		45.3			(45.3	)(i)		—
Customer deposits		14.0			—			14.0
Taxes accrued		96.5			—			96.5
Exchange gas payable		28.0			—			28.0
Deferred revenue		22.4			—			22.4
Regulatory liabilities		9.6			—			9.6
Legal and environmental		0.7			—			0.7
Accrued capital expenditures		80.3			—			80.3
Other accruals		57.3			—			57.3

Total Current Liabilities		418.8			(20.5	)		398.3

Noncurrent Liabilities
Long-term debt		—			2,746.0	(c)		2,746.0
Long-term debt-affiliated		1,848.2			(1,848.2	)(d)		—
Deferred income taxes		1,284.6			—			1,284.6
Accrued liability for postretirement and postemployment benefits		48.8			—			48.8
Regulatory liabilities		299.0			—			299.0
Asset retirement obligations		23.5			—			23.5
Other noncurrent liabilities		98.1			—			98.1

Total Noncurrent Liabilities		3,602.2			897.8			4,500.0

Total Liabilities		4,021.0			877.3			4,898.3

Equity
Net parent investment		4,027.9			(2,577.9	)(b)		—
					(1,450.0	)(f)
Common stock		—			3.2	(b)		3.2
Additional paid-in capital		—			2,574.7	(b)		2,574.7
Accumulated other comprehensive loss		(25.1	)		—			(25.1	)

Total Columbia Pipeline Group, Inc. Equity		4,002.8			(1,450.0)			2,552.8
Noncontrolling interest		946.2			—			946.2

Total Equity		4,949.0			(1,450.0	)		3,499.0

Total Liabilities and Equity	$	8,970.0		$	(572.7	)	$	8,397.3

The accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements are an integral part of these statements.

F-5

Columbia Pipeline Group, Inc.

Unaudited Pro Forma Statement of Consolidated Operations


	Year Ended December 31, 2014
	CPG Historical			Pro Forma Adjustments			Pro Forma
	(in millions)
Operating Revenues
Transportation revenues	$	990.8		$	95.7	(i)	$	1,086.5
Transportation revenues—affiliated		95.7			(95.7	)(i)		—
Storage revenues		144.0			53.2	(i)		197.2
Storage revenues-affiliated		53.2			(53.2	)(i)		—
Other revenues		64.3			—			64.3

Total Operating Revenues		1,348.0			—			1,348.0

Operating Expenses
Operation and maintenance		628.4			123.2	(i)		751.6
Operation and maintenance—affiliated		123.2			(123.2	)(i)		—
Depreciation and amortization		118.8			—			118.8
Gain on sale of assets		(34.5	)		—			(34.5	)
Property and other taxes		67.1			—			67.1

Total Operating Expenses		903.0			—			903.0

Equity Earnings in Unconsolidated Affiliates		46.6			—			46.6

Operating Income		491.6			—			491.6

Other Income (Deductions)
Interest expense		—			(113.2	)(g)		(113.2	)
Interest expense—affiliated		(62.0	)		62.0	(e)		—
Other, net		8.8			—			8.8

Total Other (Deductions)/Income, net		(53.2	)		(51.2	)		(104.4	)

Income from Continuing Operations before Income Taxes		438.4			(51.2	)		387.2
Income Taxes		169.7			(37.1	)(h)		132.6

Income from Continuing Operations		268.7			(14.1	)		254.6
Income from Discontinued Operations—net of taxes		(0.6	)		—			(0.6	)

Net Income	$	268.1		$	(14.1	)	$	254.0

Less: Net income attributable to noncontrolling interest		—			42.0	(a)		42.0

Net Income attributable to Columbia Pipeline Group, Inc.	$	268.1		$	(56.1	)	$	212.0

Basic Pro Forma Earnings per Share (See Note 3):
Continuing operations							$	0.67
Discontinued operations							$	—
Diluted Pro Forma Earnings per Share (See Note 3):
Continuing operations							$	0.67
Discontinued operations							$	—
Pro Forma Shares Outstanding:
Basic								315.1
Diluted								316.6

The accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements are an integral part of these statements.

F-6

Columbia Pipeline Group, Inc.

Unaudited Pro Forma Statement of Consolidated Operations


	Three Months Ended March 31, 2015
	CPG Historical			Pro Forma Adjustments			Pro Forma
				(in millions)
Operating Revenues
Transportation revenues	$	248.4		$	29.0 (i)		$	277.4
Transportation revenues-affiliated		29.0			(29.0	)(i)		—
Storage revenues		36.6			13.3 (i)			49.9
Storage revenues-affiliated		13.3			(13.3	)(i)		—
Other revenues		12.7			—			12.7

Total Operating Revenues		340.0			—			340.0

Operating Expenses
Operation and maintenance		118.4			28.0 (i)			146.4
Operation and maintenance-affiliated		28.0			(28.0	)(i)		—
Depreciation and amortization		32.5			—			32.5
Gain on sale of assets		(5.3	)		—			(5.3	)
Property and other taxes		19.1			—			19.1

Total Operating Expenses		192.7			—			192.7

Equity Earnings in Unconsolidated Affiliates		15.4			—			15.4

Operating Income		162.7			—			162.7

Other Income (Deductions)
Interest expense		—			(28.0	)(g)		(28.0	)
Interest expense-affiliated		(18.3	)		18.3 (e)			—
Other, net		4.6			—			4.6

Total Other Deductions, net		(13.7	)		(9.7)			(23.4	)

Income before Income Taxes		149.0			(9.7)			139.3
Income Taxes		51.9			(3.8	)(h)		48.1

Net Income	$	97.1		$	(5.9)		$	91.2

Less: Net Income attributable to noncontrolling interest		7.1			7.0	(a)		14.1

Net Income attributable to Columbia Pipeline Group, Inc.	$	90.0		$	(12.9	)	$	77.1

Basic Pro Forma Earnings per Share (See Note 3)							$	0.24
Diluted Pro Forma Earnings per Share (See Note 3)							$	0.24
Pro Forma Shares Outstanding:
Basic								316.6
Diluted								317.4

The accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements are an integral part of these statements.

F-7

Columbia Pipeline Group, Inc.

Notes to Unaudited Pro Forma Consolidated Financial Statements

1.	Basis of Presentation

The historical financial information for the year ended December 31, 2014 is derived from and should be read in conjunction with the audited historical consolidated financial statements appearing elsewhere in this Information Statement and the assumptions outlined in Note 2 below. The historical financial information for the three months ended March 31, 2015 and balance sheet information as of March 31, 2015 is derived from and should be read in conjunction with the unaudited historical consolidated financial statements of CPG appearing elsewhere in this Information Statement and the assumptions outlined in Note 2 below.

Following the Separation, we anticipate incurring incremental general and administrative expenses as a result of being a stand-alone publicly traded company, including expenses associated with separate corporate services functions, annual and quarterly reporting, tax return preparation, compliance expenses associated with the Sarbanes Oxley Act of 2002, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, and registrar and transfer agent fees. The unaudited pro forma consolidated financial statements do not reflect these additional stand-alone public company costs. No pro forma adjustment has been made for these expenses as an estimate of these expenses is not objectively determinable.

2.	Pro Forma Adjustments and Assumptions

MLP Adjustments

(a)	Reflects the adjustment to noncontrolling interest to reflect the public’s interest in the MLP resulting from the initial public offering of the MLP.

Distribution Adjustment

(b)	Reflects the issuance of shares of CPG common stock so that shares issued equals the number of shares of NiSource common stock and the elimination of NiSource’s net investment in CPG.

Financing Adjustments

(c)

Reflects the receipt of $2,721.0 million from our sale of senior unsecured notes, after estimated issuance costs totaling approximately $25.0 million and discounts totaling approximately $4.0 million. Debt issuance costs will be recorded as a deferred charge and amortized to interest expense over the respective terms of the notes. Discounts on issuance of the notes will be recorded as a reduction to the face value of the long-term debt and amortized to interest expense using the effective interest method. The following tranches of notes are outstanding:

•

$500.0 million of 2.45% Senior Notes, due 2018

•

$750.0 million of 3.30% Senior Notes, due 2020

•

$1.0 billion of 4.50% Senior Notes, due 2025

•

$500.0 million of 5.80% Senior Notes, due 2045

(d)	Reflects the use of a portion of the proceeds discussed in adjustment (c) for the repayment of $1,025.2 million of intercompany debt and short-term borrowings, net of amounts due from the money pool, between CPG and NiSource.

(e)	Reflects the elimination of interest expense incurred on intercompany debt assumed to have been repaid as discussed in adjustment (d)

F-8

(f)	Reflects the use of a portion of the proceeds discussed in adjustment (c) for a special dividend paid to NiSource in the amount of $1,450.0 million.

(g)	Reflects total interest expense on our $2,750.0 million of senior unsecured notes discussed in adjustment (c) and amortization of costs with respect to the issuance of our new $2.0 billion senior unsecured revolving credit facilities. The amount is comprised of:

•

interest expense on the notes at an annual weighted average interest rate of 4.04% and a weighted average term of 11 years; and

•

amortization of debt issuance costs, debt discounts and revolving credit facility issuance costs.

Other Adjustments

(h)	Reflects the adjustment of the provision (benefit) for income taxes for the adjustments made to income (loss) before income taxes at an estimated statutory rate of approximately 38.4% related to the Separation and the portion of taxable income borne by the public’s ownership of the MLP.

(i)

With the exception of short-term borrowings—affiliated and long-term debt—affiliated, both of which are discussed further in adjustment (d), and interest expense—affiliated which is discussed further in adjustment (e), upon completion of the Separation, amounts reflected in our historical consolidated financial statements as affiliated will be reclassified to unaffiliated.

3.	Pro Forma Earnings Per Share

The calculation of pro forma basic net income per share is calculated by dividing the pro forma net income attributable to CPG by the weighted average number of shares of NiSource common stock outstanding for the periods indicated, adjusted for a distribution ratio of one share of CPG common stock for each share of NiSource common stock outstanding. The calculation of pro forma diluted net income per share is calculated by dividing the pro forma net income attributable to CPG by the weighted average number of shares of NiSource common stock outstanding and dilutive shares of common stock outstanding for the periods indicated, adjusted for the same distribution ratio. This calculation may not be indicative of the dilutive effect that will actually result from share-based awards subsequently transferred to or granted by CPG.

F-9

Columbia Pipeline Group, Inc.

Condensed Consolidated Balance Sheets (Unaudited)


	Supplemental Pro Forma at March 31, 2015			March 31, 2015			December 31, 2014
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	7.3		$	7.3		$	0.5
Accounts receivable (less reserve of $0.6 and $0.6, respectively)		125.3			125.3			149.4
Accounts receivable-affiliated		863.0			863.0			180.0
Materials and supplies, at average cost		25.2			25.2			24.9
Exchange gas receivable		28.2			28.2			34.8
Regulatory assets		7.7			7.7			6.1
Deferred property taxes		47.8			47.8			48.9
Deferred income taxes		49.2			49.2			60.0
Prepayments and other		13.0			13.0			14.7

Total Current Assets		1,166.7			1,166.7			519.3

Investments
Unconsolidated affiliates		440.3			440.3			444.3
Other investments		2.6			2.6			2.7

Total Investments		442.9			442.9			447.0

Property, Plant and Equipment
Property, plant and equipment		8,121.6			8,121.6			7,935.4
Accumulated depreciation and amortization		(3,006.7	)		(3,006.7	)		(2,976.8	)

Net Property, Plant and Equipment		5,114.9			5,114.9			4,958.6

Other Noncurrent Assets
Regulatory assets		148.4			148.4			151.9
Goodwill		1,975.5			1,975.5			1,975.5
Postretirement and postemployment benefits assets		106.2			106.2			90.0
Deferred charges and other		15.4			15.4			15.2

Total Other Noncurrent Assets		2,245.5			2,245.5			2,232.6

Total Assets	$	8,970.0		$	8,970.0		$	8,157.5

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-10


	Supplemental Pro Forma at March 31, 2015			March 31, 2015			December 31, 2014
	(in millions)
LIABILITIES AND PARENT NET EQUITY
Current Liabilities
Current portion of long-term debt-affiliated	$	—		$	—		$	115.9
Short-term borrowings-affiliated		20.5			20.5			252.5
Accounts payable		44.2			44.2			56.0
Accounts payable-affiliated		45.3			45.3			53.6
Distribution payable to NiSource		1,450.0			—			—
Customer deposits		14.0			14.0			13.4
Taxes accrued		96.5			96.5			103.2
Exchange gas payable		28.0			28.0			34.7
Deferred revenue		22.4			22.4			22.5
Regulatory liabilities		9.6			9.6			1.3
Legal and environmental		0.7			0.7			2.0
Accrued capital expenditures		80.3			80.3			61.1
Other accruals		57.3			57.3			68.0

Total Current Liabilities		1,868.8			418.8			784.2

Noncurrent Liabilities
Long-term debt-affiliated		1,848.2			1,848.2			1,472.8
Deferred income taxes		1,284.6			1,284.6			1,255.7
Accrued liability for postretirement and postemployment benefits		48.8			48.8			53.0
Regulatory liabilities		299.0			299.0			295.7
Asset retirement obligations		23.5			23.5			23.2
Other noncurrent liabilities		98.1			98.1			96.6

Total Noncurrent Liabilities		3,602.2			3,602.2			3,197.0

Total Liabilities		5,471.0			4,021.0			3,981.2

Commitments and Contingencies (Refer to Note 14)

Equity
Net parent investment		2,577.9			4,027.9			4,210.8
Accumulated other comprehensive loss		(25.1	)		(25.1	)		(34.5	)

Total Parent Equity		2,552.8			4,002.8			4,176.3
Noncontrolling interest		946.2			946.2			—

Total Equity		3,499.0			4,949.0			4,176.3

Total Liabilities and Equity	$	8,970.0		$	8,970.0		$	8,157.5

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-11

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated and Combined Operations (Unaudited)


	Three Months Ended March 31,
	2015			2014
				*Predecessor*
	(in millions)
Operating Revenues
Transportation revenues	$	248.4		$	246.9
Transportation revenues-affiliated		29.0			28.6
Storage revenues		36.6			36.3
Storage revenues-affiliated		13.3			13.7
Other revenues		12.7			20.3

Total Operating Revenues		340.0			345.8

Operating Expenses
Operation and maintenance		118.4			137.2
Operation and maintenance-affiliated		28.0			28.5
Depreciation and amortization		32.5			29.8
Gain on sale of assets		(5.3	)		(17.5	)
Property and other taxes		19.1			18.5

Total Operating Expenses		192.7			196.5

Equity Earnings in Unconsolidated Affiliates		15.4			9.8

Operating Income		162.7			159.1

Other Income (Deductions)
Interest expense-affiliated		(18.3	)		(12.1	)
Other, net		4.6			1.9

Total Other Deductions, net		(13.7	)		(10.2	)

Income from Continuing Operations before Income Taxes		149.0			148.9
Income Taxes		51.9			55.9

Income from Continuing Operations		97.1			93.0

Loss from Discontinued Operations-net of taxes		—			(0.2	)

Net Income	$	97.1		$	92.8

Less: Net income attributable to noncontrolling interest		7.1
Net income attributable to CPG	$	90.0

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-12

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated and Combined Comprehensive Income (Unaudited)


	Three Months Ended March 31,
	2015		2014
			*Predecessor*
	(in millions, net of taxes)
Net Income	$	97.1	$	92.8
Other comprehensive income/(loss):
Net unrealized gain on cash flow hedges⁽¹⁾		0.2		0.2
Unrecognized pension and OPEB costs⁽²⁾⁽³⁾		7.0		—

Total other comprehensive income		7.2		0.2

Total Comprehensive Income	$	104.3	$	93.0

Less Comprehensive Income—Noncontrolling Interests		7.1		—

Comprehensive Income—Controlling Interests		97.2		93.0

(1)	Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.1 million and $0.2 million of tax expense in 2015 and 2014, respectively.

(2)	Unrecognized pension and other postretirement benefit (“OPEB”) costs, net of zero tax expense in 2015 and 2014.

(3)	Unrecognized pension and OPEB costs are primarily related to prior period pension and OPEB remeasurement recorded during the current period.

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-13

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated and Combined Cash Flows (Unaudited)


	Three Months Ended March 31,
	2015			2014
				*Predecessor*
	(in millions)
Operating Activities
Net income	$	97.1		$	92.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation and amortization		32.5			29.8
Deferred income taxes and investment tax credits		36.1			29.0
Deferred revenue		5.3			0.7
Stock compensation expense and 401(k) profit sharing contribution		2.1			0.9
Gain on sale of assets		(5.3	)		(17.5	)
Income from unconsolidated affiliates		(15.4	)		(9.8	)
Loss from discontinued operations		—			0.2
AFUDC equity		(3.5	)		(1.6	)
Distributions of earnings received from equity investees		18.3			7.6
Changes in Assets and Liabilities:
Accounts receivable		12.2			(5.2	)
Accounts receivable-affiliated		15.2			16.1
Accounts payable		(15.6	)		(2.8	)
Accounts payable-affiliated		(8.6	)		(9.5	)
Customer deposits		0.6			75.8
Taxes accrued		(8.8	)		(3.8	)
Exchange gas receivable/payable		(0.1	)		(0.2	)
Other accruals		(9.1	)		(4.7	)
Prepayments and other current assets		2.7			2.9
Regulatory assets/liabilities		15.3			11.3
Postretirement and postemployment benefits		(8.7	)		(8.2	)
Deferred charges and other noncurrent assets		(0.2	)		(0.2	)
Other noncurrent liabilities		1.7			0.4

Net Operating Activities from Continuing Operations		163.8			204.0
Net Operating Activities from (used for) Discontinued Operations		—			(0.4	)

Net Cash Flows from Operating Activities		163.8			203.6

Investing Activities
Capital expenditures		(163.9	)		(133.4	)
Changes in short-term lendings-affiliated		(698.0	)		(2.5	)
Proceeds from disposition of assets		10.2			4.9
Distributions from (contributions to) equity investees		1.3			(31.0	)
Other investing activities		(2.4	)		(1.8	)

Net Cash Flows used for Investing Activities		(852.8	)		(163.8	)

Financing Activities
Changes in short-term borrowings-affiliated		(232.1	)		(211.5	)
Payments of long-term debt-affiliated, including current portion		(957.8	)		—
Issuance of long-term debt-affiliated		1,217.3			171.6
Proceeds from the issuance of common units, net of offering costs		1,168.4			—
Distribution of IPO proceeds to parent		(500.0	)		—

Net Cash Flows from (used for) Financing Activities		695.8			(39.9	)

Change in cash and cash equivalents		6.8			(0.1	)
Cash and cash equivalents at beginning of period		0.5			0.4

Cash and Cash Equivalents at End of Period	$	7.3		$	0.3

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-14

Columbia Pipeline Group, Inc.

Condensed Statements of Consolidated Equity (Unaudited)


	Net Parent Investment			Accumulated Other Comprehensive Income/(Loss)			Noncontrolling Interest			Total
	(in millions)
Balance January 1, 2015	$	4,210.8		$	(34.5	)	$	—		$	4,176.3

Net Income		90.0			—			7.1			97.1
Other comprehensive income, net of tax		—			7.2			—			7.2
Allocation of AOCI to noncontrolling interest		—			2.2			(2.2	)		—
Issuance of common units of the MLP		—			—			1,168.4			1,168.4
Distribution to NiSource		(500.0	)		—			—			(500.0	)
Sale of interest in Columbia OpCo to the MLP⁽¹⁾		227.1			—			(227.1	)		—

Balance March 31, 2015	$	4,027.9		$	(25.1	)		946.2		$	4,949.0

(1)

Represents the sale of an additional 8.4% limited partner interest in CPG OpCo LP (“Columbia OpCo”), recorded at the historical carrying value of Columbia OpCo’s net assets after giving effect to the $1,168.4 million equity contribution. This decreases the noncontrolling interest by the same amount it increases the net parent investment because the MLP’s purchase price for its additional 8.4% interest in Columbia OpCo exceeded book value.

The accompanying Notes to Condensed Consolidated and Combined Financial Statements (Unaudited) are an integral part of these statements.

F-15

Columbia Pipeline Group, Inc.

Notes to Condensed Consolidated and Combined Financial Statements (Unaudited)

1.	Nature of Operations and Summary of Significant Accounting Policies

A. Company Structure and Basis of Presentation. On September 26, 2014, the board of directors of NiSource Inc. (“NiSource”) approved in principle plans to separate NiSource’s natural gas pipeline and related businesses through a pro rata distribution (the “Distribution”) to NiSource stockholders of all of the outstanding common stock of Columbia Pipeline Group, Inc. (“CPG” or the “Company”). This separation (the “Separation”) is expected to take place on July 1, 2015, subject to the satisfaction of various conditions. Following the Separation, CPG will be an independent, publicly traded company, and NiSource will not retain any ownership interest in CPG.

The accompanying condensed consolidated and combined financial statements of CPG and CPG’s predecessor (the “Predecessor”) have been prepared in connection with the proposed Separation. CPG was formed on September 26, 2014 and is a wholly owned subsidiary of NiSource. Together with the closing of the initial public offering of Columbia Pipeline Partners LP (the “MLP”), which was completed on February 11, 2015, NiSource contributed its subsidiary Columbia Energy Group (“CEG”) to CPG. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of NiSource. CEG owns the general partner of the MLP and all of the MLP’s incentive distribution rights. CPG did not have any material assets or liabilities as a separate corporate entity until the contribution from NiSource on February 11, 2015. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows for the Predecessor.

NiSource is a Delaware corporation and holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the Midwest to New England. CPG and its Predecessor are primarily comprised of NiSource’s Columbia Pipeline Group Operations reportable segment which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource.

CPG is engaged in regulated gas transportation and storage services for local distribution companies, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under a tariff at rates subject to Federal Energy Regulatory Commission (“FERC”) approval.

The Condensed Consolidated and Combined Financial Statements (Unaudited) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been condensed or omitted pursuant to those rules and regulations, although CPG believes that the disclosures made are adequate to make the information not misleading. These financial statements should be read in conjunction with the Company’s audited consolidated and combined financial statements for the year ended December 31, 2014. These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present CPG’s results of operations and financial position. Amounts reported in the Condensed Statements of Consolidated and Combined Operations (Unaudited) are not necessarily indicative of amounts expected for the respective annual periods.

CPG’s accompanying condensed consolidated and combined financial statements have been prepared in accordance with GAAP on the basis of NiSource’s historical ownership of the Company’s assets and its operations. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, LLC (“Columbia Gas Transmission”), Columbia Gulf Transmission, LLC (“Columbia Gulf”),

F-16

Columbia Midstream Group, LLC (“Columbia Midstream”), Columbia Energy Ventures, LLC (“CEVCO”), CNS Microwave, Inc., Crossroads Pipeline Company (“Crossroads”), Columbia Pipeline Group Services Company, CEG, Columbia Remainder Corporation, CPP GP LLC, the MLP, CPG OPCO GP LLC, Columbia OpCo and CPG. Also included in the condensed consolidated and combined financial statements are equity method investments Hardy Storage Company, LLC (“Hardy Storage”), Millennium Pipeline Company, L.L.C. (“Millennium Pipeline”), and Pennant Midstream, LLC (“Pennant”). All intercompany transactions and balances have been eliminated.

Subsequent events were initially evaluated through May 8, 2015, the date these financial statements were available to be issued, and have been updated for disclosure purposes through the reissuance date of May 22, 2015. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the financial statements.

2.	MLP Initial Public Offering

On December 5, 2007, NiSource formed the MLP (NYSE: CPPL) to own, operate and develop a portfolio of pipelines, storage and related assets.

On February 11, 2015, the MLP completed its initial public offering of 53.8 million common units representing limited partnership interests, constituting 53.5% of the MLP’s outstanding limited partnership interests. The MLP received $1,168.4 million of net proceeds from the initial public offering. CPG owns the general partner of the MLP, all of the MLP’s subordinated units and the incentive distribution rights. The assets of the MLP consist of a 15.7% limited partner interest in Columbia OpCo, which consists of substantially all of NiSource’s Columbia Pipeline Group Operations segment. The operations of the MLP will be consolidated in CPG’s results as long as the MLP remains a subsidiary. As of March 31, 2015, the portion of the MLP owned by the public is reflected as a noncontrolling interest in the Condensed Consolidated and Combined Financial Statements (Unaudited).

The table below summarizes the effects of changes in CPG’s ownership interest in Columbia OpCo on equity:


	Three Months Ended March 31, 2015
	(in millions)
Net income attributable to CPG	$	90.0
Increase in CPG’s net parent investment for the sale of 8.4% of Columbia OpCo		227.1
Change from net income attributable to CPG and transfers to noncontrolling interest	$	317.1

3.	Recently Issued Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2015-05, Intangibles - Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement. ASU 2015-05 clarifies guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. CPG is required to adopt ASU 2015-05 for periods beginning after December 15, 2015, including interim periods, and the guidance is permitted to be applied either (1) prospectively to all agreements entered into or materially modified after the effective date, or (2) retrospectively, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2015-05 will have on the Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. CPG is required to adopt ASU 2015-03 for periods beginning after December 15, 2015, including

F-17

interim periods, and the guidance is to be applied retrospectively with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2015-03 will have on the Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. CPG is required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. CPG is currently evaluating the impact the adoption of ASU 2015-02 will have on the Condensed Consolidated and Combined Financial Statements (Unaudited) or Notes to Condensed Consolidated and Combined Financial Statements (Unaudited).

4.	Transactions with Affiliates

In the normal course of business, CPG engages in transactions with subsidiaries of NiSource. Transactions with affiliates are summarized in the tables below:

Statement of Operations.


	Three Months Ended March 31,
	2015		2014
			*Predecessor*
	(in millions)
Transportation revenues	$	29.0	$	28.6
Storage revenues		13.3		13.7
Other revenues		0.1		0.1
Operation and maintenance expense		28.0		28.5
Interest expense		18.3		12.1
Interest income		1.0		0.1

Balance Sheet.


	March 31, 2015		December 31, 2014
	(in millions)
Accounts receivable	$	863.0	$	180.0
Current portion of long-term debt		—		115.9
Short-term borrowings		20.5		252.5
Accounts payable		45.3		53.6
Long-term debt		1,848.2		1,472.8

Transportation, Storage and Other Revenues. CPG provides natural gas transportation, storage and other services to subsidiaries of NiSource.

Operation and Maintenance Expense. CPG receives executive, financial, legal, information technology and other administrative and general services from an affiliate, NiSource Corporate Services Company (“NiSource Corporate Services”). Expenses incurred as a result of these services consist of employee compensation and benefits, outside services and other expenses. CPG is charged directly or allocated using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable. However, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity.

Interest Expense and Income. CPG was charged interest for long-term debt of $19.0 million for the three months ended March 31, 2015 and $12.2 million for the three months ended March 31, 2014, offset by

F-18

associated allowance for funds used during construction (“AFUDC”) of $1.0 million for the three months ended March 31, 2015 and $1.2 million for the three months ended March 31, 2014.

Columbia OpCo and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance Corp. (“NiSource Finance”), which became effective on the closing date of the MLP’s initial public offering. The money pool is available for Columbia OpCo and its subsidiaries’ general purposes, including capital expenditures and working capital. This new money pool agreement is discussed in connection with Short-term Borrowings below. Prior to the MLP’s initial public offering, the subsidiaries of CPG participated in a similar money pool agreement with NiSource Finance. NiSource Corporate Services administers the money pools. The cash accounts maintained by the subsidiaries of Columbia OpCo and CPG are swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and the subsidiary. The amount of interest expense and income for short-term borrowings is determined by the net position of each subsidiary in the money pool. The money pool weighted-average interest rate at March 31, 2015 and 2014 was 1.07% and 0.67%, respectively. The interest expense for short-term borrowings charged for the three months ended March 31, 2015 and 2014 was $0.3 million and $1.1 million, respectively.

Accounts Receivable. CPG includes in accounts receivable amounts due from the money pool at March 31, 2015 and December 31, 2014 of $843.5 million and $145.5 million, respectively, for subsidiaries in a net deposit position. Also included in the balance at March 31, 2015 and December 31, 2014 are amounts due from subsidiaries of NiSource for transportation and storage services of $19.5 million and $34.5 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Condensed Statements of Consolidated and Combined Cash Flows (Unaudited). All other affiliated receivables are included as Operating Activities.

Short-term Borrowings. In connection with the closing of the MLP’s initial public offering, the subsidiaries of CPG entered into an intercompany money pool agreement with NiSource Finance with $750 million of reserved borrowing capacity. Following the Separation, the agreement will be with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500 million revolving credit agreement on December 5, 2014. The CPG revolving credit agreement will not become effective until the completion of the Separation. Each of CEG, OpCo GP and Columbia OpCo is a guarantor of CPG’s revolving credit facility. As guarantors and restricted subsidiaries, CEG, OpCo GP and Columbia OpCo are subject to various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens, consolidate, merge or transfer all or substantially all of their assets, make certain investments or restricted payments, modify certain material agreements, engage in certain types of transactions with affiliates, dispose of assets, and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under Columbia OpCo’s partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business. In addition, subject to Delaware law, the board of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At March 31, 2015, neither CPG or its consolidated subsidiaries had any restricted net assets. If Columbia OpCo and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to CPG. CPG’s revolving credit agreement also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50 million. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against Columbia OpCo as a guarantor.

F-19

The balance at March 31, 2015 and December 31, 2014 of $20.5 million and $252.5 million, respectively, includes those subsidiaries of CPG in a net borrower position of the NiSource money pool discussed above. Net cash flows related to short-term borrowings are included as Financing Activities on the Condensed Statements of Consolidated and Combined Cash Flows (Unaudited).

Accounts Payable. The affiliated accounts payable primarily includes amounts due for services received from NiSource Corporate Services and interest payable to NiSource Finance.

Long-term Debt. CPG’s long-term financing requirements are satisfied through borrowings from NiSource Finance. As part of the MLP’s initial public offering, CEG contributed $1.2 billion of capital to certain subsidiaries of Columbia OpCo to repay intercompany short-term and long-term debt owed to NiSource Finance. CEG also entered into new intercompany debt agreements with NiSource Finance for $1.2 billion. Details of the long-term debt balance are summarized in the table below:


Origination Date	Interest Rate			Maturity Date		March 31, 2015		December 31, 2014
						(in millions)
November 28, 2005⁽¹⁾		5.41	%		November 30, 2015	$	—	$	115.9
November 28, 2005		5.45	%		November 28, 2016		—		45.3
November 28, 2005		5.92	%		November 28, 2025		—		133.5
November 28, 2012		4.63	%		November 28, 2032		—		45.0
November 28, 2012		4.94	%		November 30, 2037		—		95.0
December 19, 2012		5.16	%		December 21, 2037		—		55.0
November 28, 2012		5.26	%		November 28, 2042		—		170.0
December 19, 2012		5.49	%		December 18, 2042		—		95.0
December 9, 2013⁽²⁾		4.75	%		December 31, 2016		630.9		834.0
February 4, 2015		3.22	%		February 4, 2025		405.0		—
February 4, 2015		3.73	%		February 2, 2035		405.0		—
February 4, 2015		4.10	%		February 3, 2045		407.3		—

Total Long-term Debt						$	1,848.2	$	1,588.7

(1)	The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in Current portion of long-term debt-affiliated on the Condensed Consolidated and Combined Balance Sheets (Unaudited) as of December 31, 2014.

(2)	CPG may borrow at any time from the origination date to maturity date not to exceed $2.6 billion. The note carries variable interest rate of prime plus 150 basis points. All funds borrowed on the note are due December 31, 2016.

Dividends. During the three months ended March 31, 2015, CPG distributed $500.0 million of the proceeds from the MLP’s initial public offering to NiSource as a reimbursement of preformation capital expenditures with respect to the assets contributed to Columbia OpCo. CPG paid no dividends to NiSource in the three months ended March 31, 2014. There were no restrictions on the payment by CPG of dividends to NiSource.

5.	Short-Term Borrowings

On December 5, 2014, the MLP entered into a $500 million senior revolving credit facility, of which $50 million in letters of credit is available. The revolving credit facility became effective at the closing of the initial public offering of the MLP. The credit facility is available for general partnership purposes, including working capital and capital expenditures, including the funding of capital calls.

The MLP’s obligations under the revolving credit facility are unsecured. However, if the credit rating of CPG at the time of the Separation is not BB+ or better and Ba1 or better, then the MLP may be required to post collateral to secure our obligations under the revolving credit facility. The loans thereunder bear interest at the MLP’s

F-20

option at either (i) the greatest of (a) the federal funds effective rate plus 0.50 percent, (b) the reference prime rate of Wells Fargo Bank, National Association or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (“LIBOR”), plus 1.00 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP’s revolving credit facility, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP revolving credit facility. The MLP revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of NiSource, as long as NiSource remains a guarantor of the revolving credit facility, or to the credit rating of CPG, once NiSource is released as a guarantor from the MLP’s revolving credit facility.

The revolving indebtedness under the credit facility ranks equally with all the MLP’s outstanding unsecured and unsubordinated debt. NiSource, CPG, CEG, OpCo GP and Columbia OpCo have each fully guaranteed the MLP credit facility, except that NiSource will be released from its guarantee upon receipt by CPG of a rating by Moody’s and S&P.

The MLP revolving credit agreement contains various covenants and restrictive provisions which, among other things, limit the MLP’s ability and the MLP’s restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness, each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by the MLP’s organizational documents. The restricted payment provision does not prohibit the MLP or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in the MLP revolving credit agreement), and neither the MLP nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. In particular, in accordance with the MLP’s partnership agreement, the general partner has adopted a policy that the MLP will make quarterly cash distributions in amounts equal to at least the minimum quarterly distribution of $0.1675 on each common and subordinated unit. However, the determination to make any distributions of cash is subject to the discretion of the general partner. At March 31, 2015, neither the MLP or its consolidated subsidiaries had any restricted net assets. If the MLP fails to perform the obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The MLP revolving credit agreement also contains customary events of default, including cross default provisions that apply to any other indebtedness the MLP may have with an outstanding principal amount in excess of $50 million.

The MLP revolving credit agreement also contains certain negative financial covenants that will require the MLP (a) to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in the MLP revolving credit agreement), then the leverage ratio may not exceed 5.50 to 1.00 and (b) until CPG has received an investment grade credit rating to maintain a Consolidated Interest Coverage Ratio (as defined in the revolving credit agreement) of no less than 3.00 to 1.00.

As of March 31, 2015, the MLP had no borrowings and issued no letters of credit under the revolving credit facility.

F-21

6.	Gain on Sale of Assets

CPG recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. Gains on conveyances of $5.3 million and $17.5 million were recorded in earnings for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015 and December 31, 2014, gains of approximately $19.2 million and $19.6 million, respectively, were deferred pending performance of future obligations and recorded in deferred revenue on the Condensed Consolidated Balance Sheets (Unaudited).

7.	Goodwill

CPG tests its goodwill for impairment annually as of May 1 unless indicators, events or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, which is consistent with the level of discrete financial information reviewed by operating segment management. Columbia Gas Transmission Operations has been determined to be a reporting unit. The Columbia Gas Transmission Operations reporting unit is comprised of the following entities: Columbia Gas Transmission (including its equity method investments in the Millennium Pipeline and Hardy Storage joint ventures), Columbia Gulf and Crossroads.

CPG applied the qualitative step 0 analysis to its reporting unit for the annual impairment test performed as of May 1, 2014. The results of this assessment indicated that it is not more likely than not that its reporting unit fair value is less than the reporting unit carrying value.

CPG considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. No such indicators were noted that would require a subsequent goodwill impairment test.

8.	Asset Retirement Obligations

Changes in CPG’s liability for asset retirement obligations for the three months ended March 31, 2015 and 2014 are presented in the table below:


	2015		2014
			*Predecessor*
	(in millions)
Beginning Balance	$	23.2	$	26.3
Accretion expense		0.3		0.4
Additions		—		—
Settlements		—		—
Change in estimated cash flows		—		—

Ending Balance	$	23.5	$	26.7

CPG’s asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl (“PCB”) remediation and asbestos removal at several compressor and measuring stations. CPG recognizes that there are obligations to incur significant costs to retire wells associated with gas storage operations; however, the lives of these wells are indeterminable until management establishes plans for closure.

9.	Regulatory Matters

Columbia Gas Transmission Customer Settlement. In January 2015, Columbia Gas Transmission commenced the third year of the Columbia Gas Transmission long-term system modernization program. Columbia Gas Transmission expects to invest approximately $300 million in modernization investments during the year. Recovery of approximately $320 million of investments made in 2014 began on February 1, 2015.

F-22

Cost Recovery Trackers and Other Similar Mechanisms. A significant portion of the transmission and storage regulated companies’ revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under Section 4 of the Natural Gas Act. However, certain operating costs of CPG’s regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas. The FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, environmental, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system as discussed above.

10.

Equity Method Investments

Certain investments of CPG are accounted for under the equity method of accounting. Income and losses from Millennium Pipeline, Hardy Storage and Pennant are reflected in Equity Earnings in Unconsolidated Affiliates on CPG’s Condensed Statements of Consolidated and Combined Operations (Unaudited). These investments are integral to CPG’s business. Contributions are made to these equity investees to fund CPG’s share of capital projects.

Columbia Gas Transmission made no contributions to Millennium Pipeline for the three months ended March 31, 2015 and contributed $2.6 million for the three months ended March 31, 2014. Millennium Pipeline distributed $16.6 million and $7.1 million of earnings to Columbia Gas Transmission during the three months ended March 31, 2015 and 2014, respectively.

No contributions were made to Hardy Storage during the three months ended March 31, 2015 and 2014. Hardy Storage distributed $0.5 million of earnings to NiSource during each of the three months ended March 31, 2015 and 2014, respectively.

No contributions were made to Pennant for the three months ended March 31, 2015, and contributions of $28.4 million were made for the three months ended March 31, 2014. Pennant distributed $1.2 million of earnings and returned $1.3 million of capital to Columbia Midstream during the three months ended March 31, 2015. No distributions were received from Pennant during the three months ended March 31, 2014.

11.

Income Taxes

CPG’s interim effective tax rates reflect the estimated annual effective tax rates for 2015 and 2014, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2015 and 2014 were 34.8% and 37.5%, respectively. The 2014 effective tax rates differ from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences. The effective tax rate for 2015 differs from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, other permanent book-to-tax differences and income received following the MLP’s initial public offering that is not subject to income tax at the partnership level. The effective tax rate is impacted by the MLP’s initial public offering which modified the ownership structure and now reflects MLP earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes. CPG consolidates the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but excludes the related tax provision.

F-23

12.

Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of CPG. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees of CPG. The majority of employees may become eligible for these benefits if they reach retirement age while working for CPG. The expected cost of such benefits is accrued during the employees’ years of service. CPG’s current rates charged to its customers include postretirement benefit costs. Cash contributions are remitted to grantor trusts.

CPG is a participant in the consolidated NiSource defined benefit retirement plans (the “Plans”), and therefore, CPG is allocated a ratable portion of NiSource’s grantor trusts for the Plans in which its employees and retirees participate. As a result, CPG follows multiple employer accounting under the provisions of GAAP.

For the three months ended March 31, 2015, CPG has made no contributions to its pension plans and contributed $2.6 million to its other postretirement benefit plans.

The following table provides the components of CPG’s allocation of net periodic benefits cost for the three months ended March 31, 2015 and 2014:


	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
				*Predecessor*						*Predecessor*
	(in millions)
Components of net periodic benefit
Cost (Income)
Service cost	$	1.3		$	1.2		$	0.3		$	0.3
Interest cost		3.5			3.9			1.2			1.2
Expected return on assets		(7.0	)		(6.9	)		(4.6	)		(4.2	)
Amortization of prior service (credit) cost		(0.3	)		(0.2	)		(0.2	)		—
Recognized actuarial loss		2.4			1.9			—			—

Total Net Periodic Benefit Cost (Income)	$	(0.1	)	$	(0.1	)	$	(3.3	)	$	(2.7	)

13.

Fair Value

CPG has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits and short-term borrowings—affiliated. CPG’s long-term debt—affiliated is recorded at historical amounts.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Long-term debt—affiliated. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the three months ended March 31, 2015 and the year ended December 31, 2014, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

F-24

The carrying amount and estimated fair values of financial instruments were as follows:


	Carrying Amount as of March 31, 2015		Estimated Fair Value as of March 31, 2015		Carrying Amount as of December 31, 2014		Estimated Fair Value as of December 31, 2014
	(in millions)
Current portion of long-term debt—affiliated	$	—	$	—	$	115.9	$	120.0
Long-term debt—affiliated	$	1,848.2	$	1,738.4	$	1,472.8	$	1,550.4

14.

Other Commitments and Contingencies

A. Other Legal Proceedings. In the normal course of its business, CPG has been named as a defendant in various legal proceedings. In the opinion of CPG, the ultimate disposition of these currently asserted claims will not have a material impact on the Company’s condensed consolidated and combined financial statements.

B. Environmental Matters. CPG’s operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. CPG believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.

It is CPG’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that CPG will not incur fines and penalties. CPG expects a significant portion of environmental assessment and remediation costs to be recoverable through rates.

As of March 31, 2015 and December 31, 2014, CPG recorded an accrual of approximately $13.1 million and $14.3 million, respectively, to cover environmental remediation at various sites. The current portion of this accrual is included in Legal and environmental in the Condensed Consolidated Balance Sheets (Unaudited). The noncurrent portion is included in Other noncurrent liabilities in the Condensed Consolidated Balance Sheets (Unaudited). CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. As of the date of these financial statements, these expenditures are not estimable at some sites. CPG periodically adjusts its accrual as information is collected and estimates become more refined.

Air

National Ambient Air Quality Standards. The federal Clean Air Act requires the U.S. Environmental Protection Agency (“EPA”) to set National Ambient Air Quality Standards (“NAAQS”) for particulate matter and five other pollutants considered harmful to public health and the environment. Periodically the EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by electric generation, gas distribution, and gas transmission operations.

The following NAAQS were recently added or modified:

Ozone: On November 25, 2014, the EPA proposed to lower the 8-hour ozone standard from 75 ppb to within a range of 65-70 ppb. If the standard is finalized and the EPA proceeds with designations, areas where CPG operates currently designated as attainment may be re-classified as non-attainment. CPG will continue to monitor this matter and cannot estimate its impact at this time.

F-25

Nitrogen Dioxide (“NO2”): On April 12, 2010, the EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing CPG combustion sources may need to be assessed and mitigated. CPG will continue to monitor this matter and cannot estimate the impact of these rules at this time.

Waste

CPG has cleanup liabilities associated with some of its former operations. Four sites are associated with its former propane operations and ten sites associated with former petroleum operations. The total liability related to these sites was $12.4 million and $12.5 million at March 31, 2015 and December 31, 2014, respectively. The liability represents CPG’s best estimate of the cost to remediate the facilities.

15.

Accumulated Other Comprehensive Loss

The following tables display the components of Accumulated Other Comprehensive Loss for the three months ended March 31, 2015 and 2014:


	Gains and Losses on Cash Flow Hedges⁽¹⁾			Pension and OPEB Items⁽¹⁾			Accumulated Other Comprehensive Loss⁽¹⁾
	(in millions)
Balance as of January 1, 2015	$	(16.6	)	$	(17.9	)	$	(34.5	)

Other comprehensive income before reclassifications		—			6.9			6.9
Amounts reclassified from accumulated other comprehensive loss		0.2			0.1			0.3

Net current-period other comprehensive income		0.2			7.0			7.2

Allocation of AOCI to noncontrolling interest		2.2			—			2.2

Balance as of March 31, 2015	$	(14.2	)	$	(10.9	)	$	(25.1	)

Balance as of January 1, 2014	$	(17.6	)	$	(8.2	)	$	(25.8	)


				Predecessor
Other comprehensive income before reclassifications		—			—			—
Amounts reclassified from accumulated other comprehensive loss		0.2			—			0.2

Net current-period other comprehensive income		0.2			—			0.2

Balance as of March 31, 2014	$	(17.4	)	$	(8.2	)	$	(25.6	)

(1)	All amounts are net of tax. Amounts in parentheses indicate debits.

(2)	Unrecognized pension and OPEB costs are primarily related to prior period pension and OPEB remeasurement recorded during the current period.

F-26

Equity Method Investment

As Millennium Pipeline is an equity method investment, CPG is required to recognize a proportional share of Millennium Pipeline’s other comprehensive income. The remaining proportional share of unrecognized loss at March 31, 2015 of $14.2 million, net of tax, related to terminated interest rate swaps is being amortized over the period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $14.2 million and $16.6 million at March 31, 2015 and December 31, 2014, respectively, is included in gains and losses on cash flow hedges above.

16.

Other, Net


	Three Months Ended March 31,
	2015		2014
			*Predecessor*
	(in millions)
AFUDC Equity	$	3.5	$	1.6
Miscellaneous Income		1.1		0.3

Total Other, net	$	4.6	$	1.9

17.

Supplemental Cash Flow Information

The following table provides additional information regarding CPG’s Condensed Statements of Consolidated and Combined Cash Flows (Unaudited) for the three months ended March 31, 2015 and 2014:


	Three Months Ended March 31,
	2015		2014
			*Predecessor*
	(in millions)
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	98.8	$	58.9
Schedule of interest and income taxes paid:
Cash paid for interest, net of capitalized amounts	$	15.6	$	0.3
Cash paid for income taxes		9.4		19.2

18.

Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party, accounted for greater than 10% of total operating revenues for the three months ended March 31, 2015 and 2014. The following table provides the customer operating revenues and the percentage of total operating revenues for the three months ended March 31, 2015 and 2014:


	2015					2014
	Total Operating Revenues		Percentage of Total Operating Revenues			Total Operating Revenues		Percentage of Total Operating Revenues
						*Predecessor*
	(in millions)
Columbia Gas of Ohio	$	48.9		14.4	%	$	47.6		13.8	%

There was no other single customer that accounted for greater than 10% of total operating revenues for the three months ended March 31, 2015 or 2014. The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of CPG.

F-27

Columbia Pipeline Group, Inc. Predecessor

Audited Historical Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of NiSource Inc.

Merrillville, Indiana

We have audited the accompanying combined balance sheets of the predecessor of Columbia Pipeline Group, Inc. (the “Company”) as of December 31, 2014 and 2013, and the related combined statements of operations, comprehensive income, parent net equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 20 to the combined financial statements, on February 11, 2015 the Company’s parent company, NiSource Inc., completed the initial public offering of limited partner interests of Columbia Pipeline Partners LP for net proceeds of $1,170.0 million.

/s/ Deloitte & Touche LLP

Chicago, Illinois

March 13, 2015

F-28

Columbia Pipeline Group, Inc.

Consolidated and Combined Balance Sheets


	As of December 31,
	2014			2013
				*Predecessor*
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	0.5		$	0.4
Accounts receivable (less reserve of $0.6 and $0.5, respectively)		149.4			128.0
Accounts receivable—affiliated		180.0			119.3
Materials and supplies, at average cost		24.9			24.8
Exchange gas receivable		34.8			49.2
Regulatory assets		6.1			12.3
Deferred property taxes		48.9			46.8
Deferred income taxes		60.0			13.3
Prepayments and other		14.7			12.7

Total Current Assets		519.3			406.8

Investments
Unconsolidated affiliates		444.3			364.5
Other investments		2.7			8.7

Total Investments		447.0			373.2

Property, Plant and Equipment
Property, plant and equipment		7,935.4			7,195.2
Accumulated depreciation and amortization		(2,976.8	)		(2,893.1	)

Net Property, Plant and Equipment		4,958.6			4,302.1

Other Noncurrent Assets
Regulatory assets		151.9			130.3
Goodwill		1,975.5			1,975.5
Postretirement and postemployment benefits assets		90.0			88.7
Deferred charges and other		15.2			4.6

Total Other Noncurrent Assets		2,232.6			2,199.1

Total Assets	$	8,157.5		$	7,281.2

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-29


	As of December 31,
	As of December 31,
	2014			2013
				*Predecessor*
	(in millions)
LIABILITIES AND PARENT NET EQUITY
Current Liabilities
Current portion of long-term debt—affiliated	$	115.9		$	—
Short-term borrowings—affiliated		252.5			719.6
Accounts payable		56.0			71.9
Accounts payable—affiliated		53.6			41.5
Customer deposits		13.4			11.5
Taxes accrued		103.2			92.6
Exchange gas payable		34.7			48.1
Deferred revenue		22.5			15.3
Regulatory liabilities		1.3			0.8
Legal and environmental		2.0			9.1
Accrued capital expenditures		61.1			26.7
Other accruals		68.0			58.4

Total Current Liabilities		784.2			1,095.5

Noncurrent Liabilities
Long-term debt—affiliated		1,472.8			819.8
Deferred income taxes		1,255.7			1,064.6
Deferred revenue		—			17.1
Accrued liability for postretirement and postemployment benefits		53.0			37.0
Regulatory liabilities		295.7			283.9
Asset retirement obligations		23.2			26.3
Other noncurrent liabilities		96.6			21.4

Total Noncurrent Liabilities		3,197.0			2,270.1

Total Liabilities		3,981.2			3,365.6

Commitments and Contingencies (Refer to Note 13)

Parent Net Equity
Net parent investment		4,210.8			3,941.4
Accumulated other comprehensive loss		(34.5	)		(25.8	)

Total Parent Net Equity		4,176.3			3,915.6

Total Liabilities and Parent Net Equity	$	8,157.5		$	7,281.2

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-30

Columbia Pipeline Group, Inc.

Statements of Consolidated and Combined Operations


	Year Ended December 31,
	2014			2013			2012
				*Predecessor*			*Predecessor*
	(in millions)
Operating Revenues
Transportation revenues	$	990.8		$	850.9		$	679.3
Transportation revenues—affiliated		95.7			94.1			95.9
Storage revenues		144.0			142.8			144.3
Storage revenues—affiliated		53.2			53.6			52.4
Other revenues		64.3			39.1			29.4

Total Operating Revenues		1,348.0			1,180.5			1,001.3

Operating Expenses
Operation and maintenance		628.4			509.0			375.9
Operation and maintenance—affiliated		123.2			118.6			106.7
Depreciation and amortization		118.8			107.0			99.4
Gain on sale of assets		(34.5	)		(18.6	)		(0.6	)
Property and other taxes		67.1			62.2			59.2

Total Operating Expenses		903.0			778.2			640.6

Equity Earnings in Unconsolidated Affiliates		46.6			35.9			32.2

Operating Income		491.6			438.2			392.9

Other Income (Deductions)
Interest expense—affiliated		(62.0	)		(37.9	)		(29.5	)
Other, net		8.8			17.9			2.1

Total Other Deductions, net		(53.2	)		(20.0	)		(27.4	)

Income from Continuing Operations before Income Taxes		438.4			418.2			365.5
Income Taxes		169.7			146.5			139.3

Income from Continuing Operations		268.7			271.7			226.2
Income/(Loss) from Discontinued Operations—net of taxes		(0.6	)		9.0			(2.2	)

Net Income	$	268.1		$	280.7		$	224.0

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-31

Columbia Pipeline Group, Inc.

Statements of Consolidated and Combined Comprehensive Income


	Year Ended December 31,
	2014			2013		2012
				*Predecessor*		*Predecessor*
	(in millions, net of taxes)
Net Income	$	268.1		$	280.7	$	224.0
Other comprehensive income/(loss):
Net unrealized gain on cash flow hedges⁽¹⁾		1.0			1.1		1.0
Unrecognized pension and OPEB benefit (costs)⁽²⁾		(9.7	)		8.2		(3.1	)

Total other comprehensive income/(loss)		(8.7	)		9.3		(2.1	)

Total Comprehensive Income	$	259.4		$	290.0	$	221.9

(1)	Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.7 million, $0.6 million and $0.6 million tax expense in 2014, 2013 and 2012, respectively.

(2)	Unrecognized pension and other postemployment benefit (“OPEB”) costs, net of $6.1 million tax benefit in 2014, $5.3 million tax expense in 2013 and $1.9 million tax benefit in 2012.

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-32

Columbia Pipeline Group, Inc.

Statements of Consolidated and Combined Cash Flows


	Year Ended December 31,
	2014			2013			2012
				*Predecessor*			*Predecessor*
	(in millions)
Operating Activities
Net Income	$	268.1		$	280.7		$	224.0
Adjustments to Reconcile Net Income to Net Cash from Continuing Operations
Depreciation and amortization		118.8			107.0			99.4
Deferred income taxes and investment tax credits		142.6			173.9			49.0
Deferred revenue		1.6			(7.8	)		(4.1	)
Stock compensation expense and 401(k) profit sharing contribution		6.3			2.2			3.2
Loss on sale of assets		(34.5	)		(18.6	)		(0.6	)
Income from unconsolidated affiliates		(46.6	)		(35.9	)		(32.2	)
(Income)/loss from discontinued operations—net of taxes		0.6			(9.0	)		2.2
AFUDC equity		(11.0	)		(6.8	)		(1.4	)
Distributions of earnings received from equity investees		37.8			32.1			34.9
Changes in Assets and Liabilities
Accounts receivable		(20.3	)		2.8			(14.1	)
Accounts receivable—affiliated		(3.6	)		(10.1	)		14.4
Accounts payable		2.8			5.5			16.6
Accounts payable—affiliated		12.4			16.3			(12.3	)
Customer deposits		77.5			1.3			1.4
Taxes accrued		12.0			(33.8	)		40.5
Exchange gas receivable/payable		1.1			(0.5	)		1.4
Other accruals		0.9			0.8			(1.0	)
Prepayments and other current assets		(4.4	)		21.7			(25.0	)
Regulatory assets/liabilities		9.0			42.6			56.6
Postretirement and postemployment benefits		(1.3	)		(115.3	)		(14.5	)
Deferred charges and other noncurrent assets		(4.3	)		9.9			44.9
Other noncurrent liabilities		0.7			(15.6	)		(9.3	)

Net Operating Activities from Continuing Operations		566.2			443.4			474.0
Net Operating Activities from (used for) Discontinued Operations		(1.4	)		13.8			(2.6	)

Net Cash Flows from Operating Activities		564.8			457.2			471.4

Investing Activities
Capital expenditures		(747.2	)		(674.8	)		(431.6	)
Insurance recoveries		11.3			6.4			6.5
Changes in short-term lendings—affiliated		(57.2	)		(3.2	)		(21.7	)
Proceeds from disposition of assets		9.3			15.4			22.7
Contributions to equity investees		(69.2	)		(125.5	)		(20.4	)
Other investing activities		(7.1	)		(9.2	)		(8.3	)

Net Cash Flows used for Investing Activities		(860.1	)		(790.9	)		(452.8	)

Financing Activities
Changes in short-term borrowings—affiliated		(467.1	)		391.0			(111.0	)
Issuance of long-term debt—affiliated		768.9			65.1			460.0
Repayments of long-term debt—affiliated		—			—			(158.7	)
Debt related costs		(6.4	)		—			—
Dividends to parent		—			(123.0	)		(208.0	)

Net Cash Flows from (used for) Financing Activities		295.4			333.1			(17.7	)

Change in cash and cash equivalents		0.1			(0.6	)		0.9
Cash and cash equivalents at beginning of period		0.4			1.0			0.1

Cash and Cash Equivalents at End of Period	$	0.5		$	0.4		$	1.0

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-33

Columbia Pipeline Group, Inc. Predecessor

Statements of Consolidated and Combined Parent Net Equity


	Net Parent Investment			Accumulated Other Comprehensive Income/(Loss)			Total
	(in millions)
Balance January 1, 2012 *— Predecessor*	$	3,762.1		$	(33.0	)	$	3,729.1

Net Income		224.0			—			224.0
Dividends to parent		(208.0	)		—			(208.0	)
Other comprehensive loss, net of tax		—			(2.1	)		(2.1	)
Net transfers from parent		0.3			—			0.3

Balance December 31, 2012 *— Predecessor*	$	3,778.4		$	(35.1	)	$	3,743.3

Net Income		280.7			—			280.7
Dividends to parent		(123.0	)		—			(123.0	)
Other comprehensive income, net of tax		—			9.3			9.3
Net transfers from parent		5.3			—			5.3

Balance December 31, 2013 *— Predecessor*	$	3,941.4		$	(25.8	)	$	3,915.6

Net Income		268.1			—			268.1
Other comprehensive loss, net of tax		—			(8.7	)		(8.7	)
Net transfers from parent		1.3			—			1.3

Balance December 31, 2014	$	4,210.8		$	(34.5	)	$	4,176.3

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

F-34

Columbia Pipeline Group, Inc.

Notes to Consolidated and Combined Financial Statements

1.	Nature of Operations and Summary of Significant Accounting Policies

A. Company Structure and Basis of Presentation. On September 26, 2014, the board of directors of NiSource Inc. (“NiSource”) approved in principle plans to separate NiSource’s natural gas pipeline and related businesses through a pro rata distribution (the “Distribution”) to NiSource stockholders of all of the outstanding common stock of Columbia Pipeline Group, Inc. (“CPG” or the “Company”). This separation (the “Separation”) is expected to take place on July 1, 2015, subject to the satisfaction of various conditions. Following the Separation, CPG will be an independent, publicly traded company, and NiSource will not retain any ownership interest in CPG.

The accompanying consolidated and combined financial statements of CPG and CPG’s predecessor (the “Predecessor”) have been prepared in connection with the proposed Separation. CPG was formed on September 26, 2014 and is a wholly owned subsidiary of NiSource. Together with the closing of the initial public offering of Columbia Pipeline Partners LP (the “MLP”), which was completed on February 11, 2015, NiSource contributed its subsidiary Columbia Energy Group (“CEG”) to CPG (see Note 20, Subsequent Event). CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of NiSource. CEG owns the general partner of the MLP and all of the MLP’s subordinated limited partnership units and incentive distribution rights. CPG did not have any material assets or liabilities as a separate corporate entity until the contribution from NiSource on February 11, 2015. As a result of this contribution, the financial statements for periods as of and subsequent to September 26, 2014 reflect the consolidated financial position, results of operations and cash flows for CPG. All periods prior to September 26, 2014 reflect the combined financial position, results of operations and cash flows of the Predecessor.

NiSource is a Delaware corporation and holding company whose subsidiaries provide natural gas, electricity and other products and services to approximately 3.8 million customers located within a corridor that runs from the Gulf Coast through the Midwest to New England. CPG and the Predecessor are primarily comprised of NiSource’s Columbia Pipeline Group Operations reportable segment which includes natural gas transmission, storage and midstream assets and mineral rights positions and equity method investments held by wholly owned subsidiaries of NiSource.

CPG is engaged in regulated interstate gas transportation and storage services for local distribution companies (“LDCs”), marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under tariffs and at rates subject to Federal Energy Regulatory Commission (“FERC”) approval.

The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of NiSource’s historical ownership of CPG’s assets and its operations. These financial statements include the accounts of the subsidiaries: Columbia Gas Transmission, LLC (“Columbia Gas Transmission”), Columbia Gulf Transmission, LLC (“Columbia Gulf”), Columbia Midstream Group, LLC (“Columbia Midstream”), Columbia Energy Ventures, LLC (“CEVCO”), CNS Microwave, Inc., Crossroads Pipeline Company (“Crossroads”), Columbia Pipeline Group Services Company, CEG, Columbia Remainder Corporation, CPP GP LLC, the MLP, CPG OpCo GP LLC (“Opco GP”), CPG OpCo LP (“Columbia OpCo”) and CPG. Also included in the consolidated and combined financial statements are equity method investments Hardy Storage Company, LLC (“Hardy Storage”), Millennium Pipeline Company, L.L.C. (“Millennium Pipeline”), and Pennant Midstream, LLC (“Pennant”). All intercompany transactions and balances have been eliminated.

F-35

Subsequent events have been evaluated through March 13, 2015, the date these financial statements were available to be issued. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the financial statements.

B. Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

C. Cash and Cash Equivalents. Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.

D. Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is CPG’s best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

E. Basis of Accounting for Rate-Regulated Subsidiaries. CPG accounts for and reports assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated and Combined Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

In the event that regulation significantly changes the opportunity for CPG to recover its costs in the future, all or a portion of CPG’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of CPG’s or the Predecessor’s existing regulatory assets and liabilities could result. If CPG is unable to continue to apply the provisions of regulatory accounting, CPG would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, CPG’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 8, “Regulatory Matters,” in the Notes to Consolidated and Combined Financial Statements for further discussion.

F. Property, Plant and Equipment and Related AFUDC and Maintenance. Property, plant and equipment is stated at cost. CPG’s regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. CPG’s non-regulated companies depreciate non-mineral related assets on a component basis, straight-line, over the remaining service lives of the properties.

CPG capitalizes allowances for funds used during construction (“AFUDC”) on all classes of regulated property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and AFUDC equity are summarized in the table below:


	2014						2013						2012
	Debt			Equity			Debt			Equity			Debt			Equity
							*Predecessor*						*Predecessor*
Columbia Gas Transmission		0.9	%		3.0	%		2.5	%		3.2	%		2.1	%		1.7	%
Columbia Gulf		2.1	%		9.4	%		2.5	%		3.2	%		2.1	%		1.7	%

F-36

CPG follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.

G. Gas Storage Base Gas. Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were no purchases of base gas during 2014 or 2013. Please see Note 4, “Gain on Sale of Assets,” in the Notes to Consolidated and Combined Financial Statements for information regarding the sale of storage base gas in 2013. Gas storage base gas is included in Property, plant and equipment on the Consolidated and Combined Balance Sheets.

H. Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. CPG amortized $4.3 million in 2014, $5.0 million in 2013 and $3.8 million in 2012 related to software costs. CPG’s unamortized software balance was $18.3 million and $12.7 million at December 31, 2014 and 2013, respectively.

I. Goodwill. CPG has $1,975.5 million in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the Columbia Energy Group acquisition on November 1, 2000. Please see Note 6, “Goodwill,” in the Notes to Consolidated and Combined Financial Statements for further discussion.

J. Impairments. An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long-lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.

K. Revenue Recognition. Revenue is recognized as services are performed. Revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.

CPG provides shorter term transportation services, for which cash is received at inception of the service period and is recorded as deferred revenue and recognized as income over the period the services are provided.

CPG’s subsidiary CEVCO owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $43.8 million, $21.2 million and $18.5 million for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in Other revenues on the Statements of Consolidated and Combined Operations.

CPG periodically recognizes gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop or produce oil or gas from a particular property

F-37

or group of properties. The gains are initially deferred if CPG has a substantial obligation for future performance. As the obligation for future performance is satisfied the deferred revenue is relieved and the associated gain is recognized. Gains on the conveyance of mineral interest were $34.5 million, $7.3 million and zero for the years ended December 31, 2014, 2013 and 2012, respectively, and are included in Gain on sale of assets on the Statements of Consolidated and Combined Operations.

L. Estimated Rate Refunds. CPG collects revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.

M. Accounting for Exchange and Balancing Arrangements of Natural Gas. CPG enters into balancing and exchange arrangements of natural gas as part of its operations. CPG records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as Exchange gas receivable or Exchange gas payable on the Company’s Consolidated and Combined Balance Sheets, as appropriate.

N. Income Taxes and Investment Tax Credits. CPG records income taxes to recognize full inter period tax allocations. Under the liability method, deferred income taxes are provided for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Previously recorded investment tax credits of CPG were deferred on the balance sheet and are being amortized to book income over the regulatory life of the related properties to conform to regulatory policy. To the extent certain deferred income taxes of CPG are recoverable or payable through future rates, regulatory assets and liabilities have been established.

CPG joins in the filing of consolidated federal and state income tax returns with its parent company, NiSource. CPG is party to an agreement (“Tax Allocation Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Allocation Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, the Tax Allocation Agreement provides that tax benefits associated with NiSource parent’s tax losses, excluding tax benefits from interest expense on acquisition debt, are allocated to and reduce the income tax liability of all NiSource subsidiaries having a positive separate company tax liability in a particular tax year.

The amounts of such tax benefits allocated to CPG for the 2014, 2013 and 2012 tax years that were recorded in equity, were $1.3 million, $5.3 million and $0.3 million, respectively.

O. Environmental Expenditures. CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The accrual for estimated environmental expenditures are recorded on the Consolidated and Combined Balance Sheets in Legal and environmental for short-term portions of these liabilities and Other noncurrent liabilities for the respective long-term portions of these liabilities. CPG establishes regulatory assets on the Consolidated and Combined Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 13, “Other Commitments and Contingencies,” in the Notes to the Consolidated and Combined Financial Statements for further discussion.

P. Accounting for Investments. CPG accounts for its ownership interests in Millennium Pipeline using the equity method of accounting. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where CPG (or subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.

F-38

Columbia Gas Transmission also owns a 100% interest in Columbia Hardy Corporation, which has a 50% interest in Hardy Storage for the periods presented. CPG reflects the investment in Hardy Storage as an equity method investment.

Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering pipeline infrastructure and natural gas liquids processing facilities to support natural gas production in the Utica shale area of northeastern Ohio and western Pennsylvania. Columbia Midstream and Hilcorp jointly own Pennant with Columbia Midstream serving as the operator of Pennant and its facilities. CPG accounts for the joint venture under the equity method of accounting.

Q. Natural Gas and Oil Properties. CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method.

CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors.

The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2014 and 2013:


	2014		2013
			Predecessor
	(in millions)
Beginning balance	$	1.9	$	3.0
Additions pending the determination of proved reserves		20.1		6.0
Reclassifications of proved properties		(7.1)		(7.1)

Ending balance	$	14.9	$	1.9

As of December 31, 2014, there was $0.5 million of capitalized exploratory well costs that have been capitalized for more than one year relating to two projects initiated in 2013.

2.	Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that represents a strategic shift that has or will have a major impact on its operations and financial results is a discontinued operation. CPG is required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. CPG is currently evaluating what impact, if any, adoption of ASU 2014-08 will have on its Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.

F-39

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. CPG is required to adopt ASU 2014-09 for periods beginning after December 15, 2016, including interim periods, and the standard is to be applied retrospectively. Early adoption is not permitted. CPG is currently evaluating the impact the adoption of ASU 2014-09 will have on its Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.

3.	Transactions with Affiliates

In the normal course of business, CPG engages in transactions with subsidiaries of NiSource. Transactions with affiliates are summarized in the tables below:

Statement of Operations.


	Year ended December 31,
	2014		2013		2012
			*Predecessor*		*Predecessor*
	(in millions)
Transportation revenues	$	95.7	$	94.1	$	95.9
Storage revenues		53.2		53.6		52.4
Other revenues		0.3		0.3		0.3
Operation and maintenance expense		123.2		118.6		106.7
Interest expense		62.0		37.9		29.5
Interest income		0.7		0.7		0.9

Balance Sheet.


	At December 31,
	2014		2013
			*Predecessor*
	(in millions)
Accounts receivable	$	180.0	$	119.3
Current portion of long-term debt		115.9		—
Short-term borrowings		252.5		719.6
Accounts payable		53.6		41.5
Long-term debt		1,472.8		819.8

Transportation, Storage and Other Revenues. CPG provides natural gas transportation, storage and other services to subsidiaries of NiSource.

Operation and Maintenance Expense. CPG receives executive, financial, legal, information technology and other administrative and general services from an affiliate, NiSource Corporate Services Company (“NiSource Corporate Services”). Expenses incurred as a result of these services consist of employee compensation and benefits, outside services and other expenses. CPG is charged directly or allocated expenses using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable. However, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity.

F-40

Interest Expense and Income. CPG was charged interest for long-term debt of $61.6 million in 2014, $40.6 million in 2013 and $26.1 million in 2012, offset by associated AFUDC of $2.7 million in 2014, $6.8 million in 2013 and $2.3 million in 2012. Please see Note 1F “Property, Plant and Equipment and Related AFUDC and Maintenance” in the Notes to Consolidated and Combined Financial Statements for further discussion on AFUDC.

NiSource Corporate Services administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. The subsidiaries of CPG participated in the money pool for all of the periods presented in the financial statements. The cash accounts maintained by subsidiaries of CPG are swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and CPG. The amount of interest expense and income for short-term borrowings is determined by the net position of each subsidiary of CPG in the money pool. The money pool weighted-average interest rate at December 31, 2014 and 2013 was 0.70% and 0.87%, respectively. The interest expense for short-term borrowings charged in 2014, 2013 and 2012 was $3.1 million, $4.1 million and $5.7 million, respectively.

Accounts Receivable. CPG includes in accounts receivable amounts due from the money pool discussed above at December 31, 2014 and 2013 of $145.5 million and $88.3 million for subsidiaries in a net deposit position. Also included in the balance at December 31, 2014 and 2013 are amounts due from subsidiaries of NiSource for transportation and storage services of $34.5 million and $31.0 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Statements of Consolidated and Combined Cash Flows. All other affiliated receivables are included as Operating Activities.

Short-term Borrowings. The balance at December 31, 2014 and 2013 includes all subsidiaries of CPG in a net borrower position of the money pool discussed above. Net cash flows related to short-term borrowings are included as Financing Activities on the Statements of Consolidated and Combined Cash Flows.

Accounts Payable. The affiliated accounts payable balance primarily includes amounts due for services received from NiSource Corporate Services and interest payable to NiSource Finance Corp. (“NiSource Finance”).

Long-term Debt. CPG’s long-term financing requirements are satisfied through borrowings from NiSource Finance. Details of the long-term debt balance are summarized in the table below:


						At December 31,
Origination Date	Interest Rate			Maturity Date		2014		2013
								*Predecessor*
						(in millions)
November 28, 2005⁽¹⁾		5.41	%		November 30, 2015	$	115.9	$	115.9
November 28, 2005		5.45	%		November 28, 2016		45.3		45.3
November 28, 2005		5.92	%		November 28, 2025		133.5		133.5
November 28, 2012		4.63	%		November 28, 2032		45.0		45.0
November 28, 2012		4.94	%		November 30, 2037		95.0		95.0
December 19, 2012		5.16	%		December 21, 2037		55.0		55.0
November 28, 2012		5.26	%		November 28, 2042		170.0		170.0
December 19, 2012		5.49	%		December 18, 2042		95.0		95.0
December 9, 2013⁽²⁾		4.75	%		December 31, 2016		834.0		65.1

Total Long-term Debt, Including Current Portion						$	1,588.7	$	819.8

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(1)	The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in Current portion of long-term debt—affiliated on the Consolidated and Combined Balance Sheets as of December 31, 2014.

(2)	CPG may borrow at any time from the origination date to the maturity date not to exceed $2.6 billion. The note carries a variable interest rate of prime plus 150 basis points. All funds borrowed on the note are due December 31, 2016.

Dividends. CPG paid no dividends to NiSource in 2014, and the Predecessor paid $123.0 million and $208.0 million in dividends to NiSource in 2013 and 2012, respectively. There are no restrictions on the payment by CPG of dividends to NiSource.

4.	Gain on Sale of Assets

CPG recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. Gains on conveyances of $34.5 million, $7.3 million and zero were recorded in earnings in 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, deferred gains of approximately $19.6 million and $30.0 million, respectively, were deferred pending performance of future obligations and recorded in deferred revenue on the Consolidated and Combined Balance Sheets.

In 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million.

5.	Property, Plant and Equipment

Property, plant and equipment includes materials, payroll and related costs such as taxes, pensions and other employee benefits, general and administrative costs and AFUDC.

CPG’s property, plant and equipment on the Consolidated and Combined Balance Sheets are classified as follows:


	At December 31,
	2014		2013
			*Predecessor*
	(in millions)
Property, plant and equipment
Pipeline and other transmission assets	$	5,333.0	$	4,896.6
Storage facilities		1,326.5		1,253.4
Storage base gas		299.5		299.5
Gathering and processing facilities		263.3		260.5
Construction work in process		454.2		238.2
General plant, software, and other assets		258.9		247.0

Property, plant and equipment		7,935.4		7,195.2

Accumulated depreciation and amortization		(2,976.8)		(2,893.1)

Net property, plant and equipment	$	4,958.6	$	4,302.1

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The table below lists CPG’s applicable annual depreciation rates:


	Year Ended December 31,
	2014		2013		2012
			*Predecessor*		*Predecessor*
Depreciation rates
Pipeline and other transmission assets		1.00% - 2.50%		1.00% - 2.50%		1.00% - 2.50%
Storage facilities		2.19% - 3.30%		2.19% - 3.50%		2.19% - 3.50%
Gathering and processing facilities		1.67% - 2.50%		1.67% - 2.50%		1.67% - 2.50%
General plant, software, and other assets		1.00% - 10.00%		1.00% - 10.00%		1.00% - 10.00%

6.	Goodwill

CPG tests its goodwill for impairment annually as of May 1 unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, which is consistent with the level of discrete financial information reviewed by operating segment management. Columbia Gas Transmission Operations has been determined to be a reporting unit. The Columbia Gas Transmission Operations reporting unit is comprised of the following entities: Columbia Gas Transmission (including its equity method investments in the Millennium Pipeline and Hardy Storage joint ventures), Columbia Gulf and Crossroads. CPG’s goodwill assets at December 31, 2014 and 2013 were $1,975.5 million pertaining to the acquisition of CEG on November 1, 2000.

The Predecessor completed a quantitative (“step 1”) fair value measurement of its reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded its carrying value, indicating that no impairment existed.

In estimating the fair value of the Columbia Gas Transmission Operations reporting unit for the May 1, 2012 test, the Predecessor used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for the reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five-year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Predecessor utilized three market-based models to estimate the fair value of the reporting unit: (i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated using multiples and assumptions inherent in today’s market. The degree of judgment involved and reliability of inputs into each model were considered in weighting the various approaches. The resulting estimate of fair value of the reporting unit, using the weighted average of the income and market approaches, exceeded their carrying values, indicating that no impairment exists under step 1 of the annual impairment test.

Certain key assumptions used in determining the fair values of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Predecessor used the discount rate of 5.60% for Columbia Gas Transmission Operations, resulting in excess fair value of approximately $1,643.0 million.

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In September 2011, the FASB issued ASU 2011-08, which allows entities testing goodwill for impairment the option of performing a qualitative (“step 0”) assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that based on that assessment it is more likely than not that its fair value is less than its carrying amount.

The Predecessor applied the qualitative step 0 analysis to its reporting unit for the annual impairment test performed as of May 1, 2014. For the 2014 qualitative step 0 test, the Predecessor assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The results of this assessment indicated that it is not more likely than not that its reporting unit fair values are less than the reporting unit carrying value.

The Predecessor considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. No such indicators were noted that would require a goodwill impairment test subsequent to May 1, 2014.

7.	Asset Retirement Obligations

Changes in CPG’s liability for asset retirement obligations for the years 2014 and 2013 are presented in the table below:


	2014		2013
			*Predecessor*
	(in millions)
Beginning Balance	$	26.3	$	19.2
Accretion expense		1.5		1.3
Additions		2.2		6.3
Settlements		(6.6)		(1.2)
Change in estimated cash flow		(0.2)		0.7

Ending Balance	$	23.2	$	26.3

CPG’s asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl (“PCB”) remediation and asbestos removal at several compressor and measuring stations. CPG recognizes that there are obligations to incur significant costs to retire wells associated with gas storage operations. However, the lives of these wells are indeterminable until management establishes plans for closure.

Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate-regulated subsidiaries are classified as Regulatory liabilities on the Consolidated and Combined Balance Sheets.

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8.	Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets and liabilities of CPG were comprised of the following items:


	At December 31,
	2014		2013
			*Predecessor*
	(in millions)
Assets
Unrecognized pension benefit and other postretirement benefit costs	$	120.9	$	102.0
Other postretirement costs		10.8		13.8
Deferred taxes on AFUDC equity		21.8		15.6
Other		4.5		11.2

Total Regulatory Assets	$	158.0	$	142.6


	At December 31,
	2014		2013
			*Predecessor*
	(in millions)
Liabilities
Cost of removal	$	157.6	$	164.2
Regulatory effects of accounting for income taxes		10.9		11.4
Unrecognized pension benefit and other postretirement benefit costs		8.3		20.0
Other postretirement costs		117.3		88.3
Other		2.9		0.8

Total Regulatory Liabilities	$	297.0	$	284.7

No regulatory assets are earning a return on investment at December 31, 2014. Regulatory assets of $23.9 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 30 years.

Assets:

Unrecognized pension benefit and other postretirement benefit costs—In 2007, the Predecessor adopted updates of Accounting Standards Codification (“ASC”) 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Other postretirement costs—Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.

Deferred taxes on AFUDC equity—ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. CPG is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized.

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Liabilities:

Cost of removal—Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the rate-regulated subsidiaries for future costs to be incurred.

Regulatory effects of accounting for income taxes—Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates in association with related depreciation on property.

Unrecognized pension benefit and other postretirement benefit costs—In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the benefits as a regulatory liability in accordance with regulatory orders or as a result of regulatory precedent.

Other postretirement costs—Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in CPG’s results, which exceeds the amount funded in the plan.

Regulatory Matters

Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved a modernization settlement (the “Settlement”). In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter.

The Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25 million in revenues annually thereafter.

The Settlement includes a capital cost recovery mechanism (“CCRM”), a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system. The CCRM provides for a 14% revenue requirement with a portion designated as a recovery of increased taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission’s transportation shippers. The CCRM will not exceed $300 million per year in investment in eligible facilities, subject to a 15% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term. On December 31, 2013, Columbia Gas Transmission made its first annual CCRM filing, with billing rates effective February 1, 2014. Through this filing, Columbia Gas Transmission will begin collecting its revenue requirements for the $299.2 million spent on eligible modernization facilities in 2013. For the first annual CCRM period, these revenue requirements will total approximately $38.9 million. On January 30, 2014, the FERC approved Columbia Gas Transmission’s first year CCRM filing.

On January 29, 2015, Columbia Gas Transmission received FERC approval of its December 2014 filing to recover costs associated with the second year of its comprehensive system modernization program. Total

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program spend to date is $618.1 million. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems.

Cost Recovery Trackers and Other Similar Mechanisms. A significant portion of CPG’s regulated companies’ revenue is related to the recovery of their operating costs, the review and recovery of which occurs via standard regulatory proceedings with the FERC under Section 7 of the Natural Gas Act of 1938. However, as certain operating costs of CPG’s regulated transmission and storage companies are significant and recurring in nature, such as fuel for compression and lost and unaccounted for gas, the FERC allows for the recovery of such costs via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of its costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect. Other such costs under regulatory tracking mechanisms include upstream pipeline transmission, electric compression, environmental, operational purchases and sales of natural gas, and the revenue requirement for capital investments made under Columbia Gas Transmission’s long-term plan to modernize its interstate transmission system as discussed above.

9.	Equity Method Investments

Certain investments of CPG are accounted for under the equity method of accounting. Income and losses from Millennium Pipeline, Hardy Storage and Pennant are reflected in Equity Earnings in Unconsolidated Affiliates on CPG’s Statements of Consolidated and Combined Operations. These investments are integral to CPG’s business. Contributions are made to these equity investees to fund CPG’s share of capital projects.

The following is a list of CPG’s equity method investments at December 31, 2014:


Investee	Type of Investment		% of Voting Power or Interest Held
Hardy Storage Company, LLC		LLC Membership		50.00	%
Pennant Midstream, LLC		LLC Membership		50.00	%
Millennium Pipeline Company, L.L.C.		LLC Membership		47.50	%

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As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in the aggregate, material to CPG’s business, the following table contains condensed summary financial data. These investments are accounted for under the equity method of accounting and are recorded within Unconsolidated Affiliates on CPG’s Consolidated and Combined Balance Sheets and CPG’s portion of the results is reflected in Equity Earnings in Unconsolidated Affiliates on CPG’s Statements of Consolidated and Combined Operations.


	Year Ended December 31,
	2014			2013		2012
				*Predecessor*		*Predecessor*
	(in millions)
Millennium Pipeline
Statement of Income Data:
Net Revenues	$	190.5		$	157.8	$	152.3
Operating Income		128.8			101.3		97.7
Net Income		89.6			63.0		57.1
Balance Sheet Data:
Current Assets		32.1			38.3		33.7
Noncurrent Assets		1,016.3			1,033.8		1,013.4
Current Liabilities		42.6			58.8		42.7
Noncurrent Liabilities		568.3			599.7		631.4
Total Members’ Equity		437.5			413.6		373.0
Hardy Storage
Statement of Income Data:
Net Revenues	$	23.6		$	24.4	$	24.4
Operating Income		16.1			16.5		16.4
Net Income		10.6			10.6		10.0
Balance Sheet Data:
Current Assets		12.0			12.5		9.7
Noncurrent Assets		157.4			160.2		164.1
Current Liabilities		17.1			18.3		15.6
Noncurrent Liabilities		77.4			85.7		93.8
Total Members’ Equity		74.9			68.7		64.4
Pennant
Statement of Income Data:
Net Revenues	$	8.5		$	2.0	$	—
Operating (Loss)/Income		(2.4	)		1.3		—
Net (Loss)/Income		(2.4	)		1.3		—
Balance Sheet Data:
Current Assets		23.7			34.1		16.4
Noncurrent Assets		380.0			231.9		31.0
Current Liabilities		8.6			11.4		2.0
Total Members’ Equity		395.1			254.6		45.4

Contributions made to Millennium Pipeline to fund its construction activities were $2.6 million, $16.6 million and $17.5 million for 2014, 2013 and 2012, respectively. Millennium Pipeline distributed $35.6 million, $29.0 million and $31.4 million of earnings to Columbia Gas Transmission during 2014, 2013 and 2012, respectively.

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No contributions were made to Hardy Storage during 2014, 2013 or 2012. Hardy Storage distributed $2.2 million, $3.1 million and $3.5 million of available accumulated earnings to Columbia Gas Transmission during 2014, 2013 and 2012, respectively.

Pennant was formed by Columbia Midstream and Hilcorp Energy Company (“Hilcorp”) in 2012. Contributions made to Pennant were $66.6 million, $108.9 million and $2.9 million for 2014, 2013 and 2012, respectively. No distributions have been received from Pennant.

10.

Income Taxes

The components of income tax expense (benefit) were as follows:


	Year Ended December 31,
	2014		2013		2012
			*Predecessor*		*Predecessor*
	(in millions)
Income Taxes
Current
Federal	$	19.5	$	(15.5)	$	75.2
State		7.6		(11.9)		15.0

Total Current		27.1		(27.4)		90.2

Deferred
Federal		119.2		157.4		44.9
State		23.5		16.6		4.2

Total Deferred		142.7		174.0		49.1

Deferred Investment Credits		(0.1)		(0.1)		—

Total Income Taxes	$	169.7	$	146.5	$	139.3

Total income taxes from continuing operations were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:


	Year Ended December 31,
	2014			2013			2012
				*Predecessor*			*Predecessor*
	(in millions)
Book income from Continuing Operations before income taxes	$	438.4		$	418.2		$	365.5
Tax expenses at statutory federal income tax rate		153.5	35.0%		146.4	35.0%		127.9	35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit		20.3	4.6		3.0	0.7		12.4	3.4
Amortization of deferred investment tax credits		(0.1)	—		(0.2)	(0.1)		—	—
Nondeductible expenses		0.9	0.2		0.9	0.2		0.9	0.2
AFUDC Equity		(3.7)	(0.8)		(2.4)	(0.6)		(0.4)	(0.1)
Other, net		(1.2)	(0.3)		(1.2)	(0.2)		(1.5)	(0.4)

Total Income Taxes	$	169.7	38.7%	$	146.5	35.0%	$	139.3	38.1%

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On March 7, 2013, the Congressional Joint Committee on Taxation (the “Joint Committee”) took no exception to the conclusions reached by the Internal Revenue Service (“IRS”) in its 2008-2010 audit examination of NiSource. Therefore, in 2013, CPG recognized a federal income tax receivable of $4.1 million that was related to the 2008 and 2009 tax. CPG received payments of $27.4 million in 2013 of principal and interest from the IRS related to the audit examination.

The recognition of the receivables did not materially affect tax expense or net income.

On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 (“ATRA”). ATRA, among other things, extended retroactively the research credit under Internal Revenue Code Section 41 until December 31, 2013, and also extended and modified 50% bonus depreciation for 2013. CPG recorded the effects of ATRA in 2013. On December 19, 2014, the President signed into law the Tax Increase Prevention Act (“TIPA”). TIPA extended and modified 50% bonus depreciation for 2014. CPG recorded the effects of TIPA in the fourth quarter 2014. In general, 50% bonus depreciation is available for property placed in service before January 1, 2015, or in the case of certain property having longer production periods, before January 1, 2016. The retroactive extension of the research credit did not have a significant effect on net income.

Tangible Property Regulations and Repairs

On December 27, 2011, the United States Treasury Department (the “Treasury Department”) and the IRS issued temporary and proposed regulations effective for years beginning on or after January 1, 2012 that, among other things, provided guidance on whether expenditures qualified as deductible repairs (the “Tangible Property Regulations”). In addition to repairs related rules, the proposed and temporary regulations provided additional guidance related to capitalization of tangible property. Among other things, these rules provide guidance for the treatment of materials and supplies, dispositions of property, and related elections. On March 15, 2012, the IRS issued a directive to discontinue exam activity related to positions on this issue taken on original tax returns for years beginning before January 1, 2012 (commonly referred to as the “Stand-down Position”).

On October 2, 2012 and later incorporated by reference in the Revenue Agent’s Report dated November 14, 2012 for the 2008 to 2010 tax years, the Predecessor received an audit adjustment that adopted the Stand-down Position. The effect of this adjustment is to allow the repairs claims as filed and to defer review until a new method is adopted in 2012 or a subsequent acceptable year.

On November 20, 2012, the Treasury Department and IRS issued Notice 2012-73, which in relevant part stated that (i) final regulations would be issued in 2013, and (ii) the final regulations will contain changes from the temporary regulations. The Notice in essence defers the requirement of adopting the temporary regulations until 2013 and the final regulations until 2014.

On September 13, 2013, the IRS and the Treasury Department issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers may elect early adoption of the regulations for the 2012 or 2013 tax year. CPG did not early adopt the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. CPG will likely adopt this Revenue Procedure for income tax filings for 2014. The final regulations did not materially affect the financial statements.

Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

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The principal components of CPG’s net deferred tax liability were as follows:


	At December 31,
	2014		2013
			*Predecessor*
	(in millions)
Deferred tax liabilities
Accelerated depreciation and other property differences	$	1,235.2	$	1,087.9
Pension and other postretirement/postemployment benefits		27.7		20.3
Other regulatory assets		62.8		58.2
Other, net		62.9		53.8

Total Deferred Tax Liabilities		1,388.6		1,220.2

Deferred tax assets
Deferred investment tax credits and other regulatory liabilities		(116.7)		(107.9)
Net operating loss carryforward and AMT credit carryforward		(70.3)		(48.0)
Other accrued liabilities		(5.9)		(13.0)

Total Deferred Tax Assets		(192.9)		(168.9)

Net Deferred Tax Liabilities less Deferred Tax Assets		1,195.7		1,051.3

Less: Deferred income taxes related to current assets and liabilities		(60.0)		(13.3)

Non-Current Deferred Tax Liabilities	$	1,255.7	$	1,064.6

The net operating loss carryforward includes a federal carryforward deferred tax asset of $69.4 million that will expire in 2033.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:


Reconciliation of Unrecognized Tax Benefits	2014		2013		2012
			*Predecessor*		*Predecessor*
	(in millions)
Unrecognized Tax Benefits—Opening Balance	$	0.1	$	4.9	$	15.3
Gross decreases—tax positions in prior period		(0.1)		(4.8)		(10.4)
Gross increases—current period tax positions		—		—		—

Unrecognized Tax Benefits—Ending Balance	$	—	$	0.1	$	4.9

Offset for outstanding IRS refunds		—		—		(4.8)
Offset for net operating loss carryforwards		—		—		—

Balance—Net of Refunds and Net Operating Loss Carryforwards	$	—	$	0.1	$	0.1

Based upon its intent to comply with Internal Revenue Procedures, Tangible Property Regulations and the Stand-down Position audit adjustment, the Predecessor determined that the unrecognized tax benefit associated with the requested change in tax accounting method filed for 2008 related to gas transmission required a re-measurement under the provisions of ASC 740. Therefore, in 2012 the Predecessor recognized an income tax receivable of $15.6 million related to the 2008 and 2009 tax years, previously unrecognized. Except for interest recorded on the tax receivables, the recognition of the receivables did not materially affect tax expense or net income.

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In 2010, the Predecessor received permission to change its method of accounting for capitalizing overhead costs. the Predecessor recorded an unrecognized tax benefit related to this uncertain tax position of $2.4 million in 2010. In 2011, this estimate was revised to $4.2 million. In 2012, the IRS completed fieldwork for the audit for the years 2008-2010, pending Joint Committee review. The Predecessor revised the unrecognized tax benefit related to this issue to incorporate 2012 activity. At December 31, 2012, the unrecognized tax benefits were $4.2 million. This issue was resolved in 2013.

The total amount of unrecognized tax benefits at December 31, 2014, 2013 and 2012 that, if recognized, would affect the effective tax rate is zero for December 31, 2014 and $0.1 million for December 31, 2013 and 2012. As of December 31, 2014, CPG did not anticipate any significant changes to its liabilities for unrecognized tax benefits over the twelve months ended December 31, 2015. As of December 31, 2012, it was reasonably possible that a $4.2 million decrease in unrecorded tax benefits could occur in 2013 due primarily to Joint Committee review of the 2008-2010 federal audit. The results of the review are described above.

CPG recognizes accrued interest on unrecognized tax benefits, accrued interest on other income tax liabilities, and tax penalties in income tax expense. With respect to its unrecognized tax benefits, CPG or the Predecessor, as applicable, recorded amounts under $0.1 million in interest expense in the Statements of Consolidated and Combined Operations for the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014 and 2013, CPG or the Predecessor, as applicable, reported amounts under $0.1 million, of accrued interest payable on unrecognized tax benefits on its Consolidated and Combined Balance Sheets. There were no accruals for penalties recorded in the Statements of Consolidated and Combined Operations for the years ended December 31, 2014, 2013 and 2012 and there were no balances for accrued penalties recorded on the Consolidated and Combined Balance Sheets as of December 31, 2014 and 2013.

CPG is subject to income taxation in the United States and various state jurisdictions, primarily West Virginia, Virginia, Pennsylvania, Kentucky, Louisiana, Mississippi, Maryland, Tennessee, New Jersey and New York.

Because CPG’s parent, NiSource, is part of the IRS’s Large and Mid-Size Business program, each year’s federal income tax return is typically audited by the IRS. As of December 31, 2014, tax years through 2010 have been audited and are effectively closed to further assessment, except for immaterial carryforward amounts. The audit of tax years 2011 and 2012 began in 2013. NiSource is involved in the Compliance Assurance Program for tax years 2013 and 2014.

The statute of limitations in each of the state jurisdictions in which CPG operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. As of December 31, 2014, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

11.

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefit Plans’ Asset Management. NiSource employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-

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term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Other assets such as private equity funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner. However, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

NiSource utilizes a building block approach with proper consideration of diversification and rebalancing in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for the NiSource plan assets represents a long-term view and are listed in the following table below.

In 2012, a dynamic asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, real estate, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by market value of qualified pension plan assets divided by the projected benefit obligations of the qualified pension plans). The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on December 31, 2014 are as follows:

Asset Mix Policy of Funds:


	Defined Benefit Pension Plan						Postretirement Benefit Plan
Asset Category	Minimum			Maximum			Minimum			Maximum
Domestic Equities		25	%		45	%		35	%		55	%
International Equities		15	%		25	%		15	%		25	%
Fixed Income		23	%		37	%		20	%		50	%
Real Estate/Private Equity/Hedge Funds		0	%		15	%		0	%		0	%
Short-term Investments		0	%		10	%		0	%		10	%

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Pension Plan and Postretirement Plan Asset Mix allocated to CPG and the Predecessor at December 31, 2014 and December 31, 2013:


December 31, 2014	Defined Benefit Pension Plan Assets					Postretirement Benefit Plan Assets
Asset Class	Asset Value		% of Total Assets			Asset Value		% of Total Assets
	(in millions)					(in millions)
Domestic Equities	$	144.2		41.1	%	$	105.7		47.2	%
International Equities		63.3		18.1	%		41.2		18.4	%
Fixed Income		120.9		34.4	%		76.3		34.1	%
Real Estate/Private Equity/Hedge Funds		17.7		5.0	%		—		0.0	%
Cash/Other		4.9		1.4	%		0.6		0.3	%

	$	351.0		100.0	%	$	223.8		100.0	%


December 31, 2013 *— Predecessor*	Defined Benefit Pension Plan Assets					Postretirement Benefit Plan Assets
Asset Class	Asset Value		% of Total Assets			Asset Value		% of Total Assets
	(in millions)					(in millions)
Domestic Equities	$	139.0		40.4	%	$	100.7		48.0	%
International Equities		71.8		20.8	%		39.9		19.0	%
Fixed Income		96.9		28.1	%		60.9		29.0	%
Real Estate/Private Equity/Hedge Funds		19.1		5.6	%		—		0.0	%
Cash/Other		17.7		5.1	%		8.2		4.0	%

	$	344.5		100.0	%	$	209.7		100.0	%

The categorization of investments into the asset classes in the table above are based on definitions established by the NiSource Benefits Committee.

Fair Value Measurements. The following tables set forth, by level within the fair value hierarchy, the Master Trust and OPEB investment assets at fair value as of December 31, 2014 and 2013. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total Master Trust and OPEB investment assets at fair value classified within Level 3 were $17.6 million and $18.9 million as of December 31, 2014 and 2013, respectively. Such amounts were approximately 3% of the Master Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2014 and 2013.

Valuation Techniques Used to Determine Fair Value:

Level 1 Measurements

Most common and preferred stock is traded in active markets on national and international securities exchanges and is valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.

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Level 2 Measurements

Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.

Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are classified as Level 2. The funds’ underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments.

Level 3 Measurements

Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds’ underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods.

The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days’ notice. Private equity investment strategies include buy-out, venture capital, growth equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships.

Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership’s fair value as recorded in the partnerships’ audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds’ underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation.

For the year ended December 31, 2014, there were no significant changes to valuation techniques to determine the fair value of NiSource’s pension and other postretirement benefits’ assets.

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The following table reflects CPG’s allocation of pension and other postretirement benefit amounts:


Fair Value Measurements	December 31, 2014			Quoted Prices in Assets (Level 1)		Significant Inputs (Level 2)		Significant Inputs (Level 3)
	(in millions)
Pension plan assets:
Cash	$	2.6		$	2.6	$	—	$	—
Equity securities
U.S. equities		0.1			0.1		—		—
International equities		20.3			20.2		0.1		—
Fixed income securities
Government		17.8			15.7		2.1		—
Corporate		38.7			—		38.7		—
Mortgages/Asset backed securities		0.4			—		0.4		—
Other fixed income		0.1			—		—		0.1
Commingled funds
Short-term money markets		4.9			—		4.9		—
U.S. equities		144.2			—		144.2		—
International equities		42.1			—		42.1		—
Fixed income		61.6			—		61.6		—
Private equity limited partnerships
U.S. multi-strategy⁽¹⁾		8.5			—		—		8.5
International multi-strategy⁽²⁾		5.3			—		—		5.3
Distressed opportunities		1.1			—		—		1.1
Real estate		2.6			—		—		2.6

Pension plan assets subtotal		350.3			38.6		294.1		17.6

Other postretirement benefit plan assets
Commingled funds
Short-term money markets		0.8			—		0.8		—
U.S. equities		14.3			—		14.3		—
Mutual funds
U.S. equities		91.3			91.3		—		—
International equities		41.2			41.2		—		—
Fixed income		76.2			76.2		—		—

Other postretirement benefit plan assets subtotal		223.8			208.7		15.1		—

Due to brokers, net⁽³⁾		(0.1	)
Accrued investment income/dividends		0.1
Net receivables		0.7

Total pension and other postretirement benefit plan assets	$	574.8		$	247.3	$	309.2	$	17.6

(1)	This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.

(2)	This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

(3)	This class represents pending trades with brokers.

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	Balance at January 1, 2014		Total gains or losses (unrealized/ realized)			Purchases		(Sales)			Transfers into/(out of) Level 3		Balance at December 31, 2014
Fixed income securities
Other fixed income	$	—	$	—		$	0.1	$	—		$	—	$	0.1
Private equity limited partnerships
U.S. multi-strategy		8.7		0.4			0.4		(1.0	)		—		8.5
International multi-strategy		5.8		(0.1	)		0.1		(0.5	)		—		5.3
Distressed opportunities		1.4		0.1			—		(0.4	)		—		1.1
Real estate		3.0		0.3			—		(0.7	)		—		2.6

Total	$	18.9	$	0.7		$	0.6	$	(2.6	)	$	—	$	17.6

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The following table reflects the Predecessor’s allocation of pension and other postretirement benefit amounts:


	*Predecessor*
Fair Value Measurements	December 31, 2013			Quoted Prices in Assets (Level 1)		Significant Inputs (Level 2)		Significant Inputs (Level 3)
	(in millions)
Pension plan assets:
Cash	$	1.4		$	1.4	$	—	$	—
Equity securities
U.S. equities		50.1			50.1		—		—
International equities		23.6			23.4		0.2		—
Fixed income securities
Government		19.0			12.8		6.2		—
Corporate		25.3			—		25.3		—
Mortgage/Asset backed securities		9.3			—		9.3		—
Commingled funds
Short-term money markets		12.3			—		12.3		—
U.S. equities		87.3			—		87.3		—
International equities		47.8			—		47.8		—
Fixed income		43.2			—		43.2		—
Private equity limited partnerships
U.S. multi-strategy⁽¹⁾		8.7			—		—		8.7
International multi-strategy⁽²⁾		5.8			—		—		5.8
Distressed opportunities		1.4			—		—		1.4
Real estate		3.0			—		—		3.0

Pension plan assets subtotal		338.2			87.7		231.6		18.9

Other postretirement benefit plan assets
Commingled funds
Short-term money markets		8.4			—		8.4		—
U.S. equities		13.7			—		13.7		—
Mutual funds
U.S. equities		87.0			87.0		—		—
International equities		39.9			39.9		—		—
Fixed income		60.7			60.7		—		—

Other postretirement benefit plan assets subtotal		209.7			187.6		22.1		—

Due to brokers, net⁽³⁾		(1.6	)
Accrued investment income/dividends		0.6
Net receivables⁽⁴⁾		7.3

Total pension and other postretirement benefit plan assets	$	554.2		$	275.3	$	253.7	$	18.9

(1)	This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily inside the United States.

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(2)	This class includes limited partnerships/fund of funds that invest in diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

(3)	This class represents pending trades with brokers.

(4)	Reflects $7.3 million in December 31, 2013 hedge funds redemptions in which cash has not been received. These hedge fund investments had previously been included as level 3 investments prior to the redemptions.


	*Predecessor*
	Balance at January 1, 2013		Total gains or losses (unrealized/ realized)			Purchases		(Sales)			Transfers into/(out of) Level 3		Balance at December 31, 2013
Fixed income securities
Government	$	0.1	$	—		$	—	$	(0.1	)	$	—	$	—
Other fixed income
Commingled funds		—		—			0.1		(0.1	)		—		—
Fixed income		16.2		0.3			—		(16.5	)		—		—
Hedge fund of funds		—
Multi-strategy		8.1		—			—		(8.1	)		—		—
Equities-market neutral		4.9		—			—		(4.9	)		—		—
Private equity limited partnerships
U.S. multi-strategy		9.7		0.1			0.5		(1.6	)		—		8.7
International multi-strategy		6.7		(0.5	)		0.1		(0.5	)		—		5.8
Distressed opportunities		1.8		0.1			—		(0.5	)		—		1.4
Real estate		3.1		0.3			—		(0.4	)		—		3.0

Total	$	50.6	$	0.3		$	0.7	$	(32.7	)	$	—	$	18.9

As noted above, CPG follows multiple employer accounting under the provisions of GAAP, and, therefore, is allocated a ratable portion of NiSource’s grantor trusts for the plans in which its employees and retirees participate. The allocation of the fair value of assets is based upon the ratable share of plan funding and participant benefit payments. Investment activity within the trust occurs at the trust level, and CPG is allocated a portion of investment gains and losses based on its percentage of the total NiSource projected benefit obligation. For the year ended December 31, 2014, NiSource had purchases, sales and transfers into (out of) Level 3 assets of $3.5 million, $(16.6) million, and zero, respectively. The net realized and unrealized gain on Level 3 assets was $5.4 million. CPG’s allocation of the activity in 2014 was 15.1%.

For the year ended December 31, 2013, NiSource had purchases, sales and transfers into (out of) Level 3 assets of $4.7 million, $(208.7) million, and $(0.2) million, respectively. The net realized and unrealized gain on Level 3 assets was $2.2 million. CPG’s allocation of the activity in 2013 was 15.2%.

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Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure. The following table provides a reconciliation of the plans’ funded status and amounts reflected in CPG’s or the Predecessor’s, as applicable, balance sheet at December 31 based on a December 31 measurement date:


	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in millions)
Change in projected benefit obligation⁽¹⁾
Benefit obligation at beginning of year	$	376.7		$	430.1		$	120.9		$	142.8
Service cost		4.8			4.9			1.1			1.5
Interest cost		15.7			14.6			5.2			5.4
Plan participants’ contributions		—			—			3.0			2.1
Plan amendments		—			—			—			4.2
Actuarial loss (gain)		22.7			(27.1	)		5.7			(23.8	)
Settlement loss		—			3.0			—			—
Benefits paid		(22.3	)		(48.8	)		(12.4	)		(11.5	)
Estimated benefits paid by incurred subsidiary		—			—			0.7			0.2

Projected benefit obligation at end of year	$	397.6		$	376.7		$	124.2		$	120.9
Change in plan assets
Fair value of plan assets at beginning of year	$	344.5		$	334.7		$	209.7		$	169.2
Actual return on plan assets		21.1			44.8			11.6			30.8
Employer contributions		7.7			13.8			11.9			19.1
Plan participants’ contributions		—			—			3.0			2.1
Benefits paid		(22.3	)		(48.8	)		(12.4	)		(11.5	)

Fair value of plan assets at end of year	$	351.0		$	344.5		$	223.8		$	209.7

Funded status at end of year	$	(46.6	)	$	(32.2	)	$	99.6		$	88.8


	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in millions)
Amounts recognized in the balance sheet consist of:
Noncurrent Assets	$	—		$	—		$	113.1		$	101.6
Current liabilities		—			—			—			(1.1	)
Noncurrent liabilities		(46.6	)		(32.2	)		(13.5	)		(11.7	)

Net amount recognized at end of year⁽²⁾	$	(46.6	)	$	(32.2	)	$	99.6		$	88.8

Amounts recognized in accumulated other comprehensive income or as regulatory assets/liabilities⁽³⁾
Unrecognized prior service credit	$	(4.7	)	$	(5.9	)	$	(2.6	)	$	(2.9	)
Unrecognized actuarial loss/(gain)		148.7			127.3			(12.5	)		(24.2	)

	$	144.0		$	121.4		$	(15.1	)	$	(27.1	)

(1)	The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.

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(2)	CPG recognizes in its balance sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.

(3)

CPG determined that the future recovery of pension and other postretirement benefits costs is probable. CPG recorded regulatory assets and liabilities of $120.9 million and $8.3 million, respectively, as of December 31, 2014 and the Predecessor recorded $101.9 million and $20.0 million, respectively, as of December 31, 2013, that would otherwise have been recorded to accumulated other comprehensive loss.

CPG’s or the Predecessor’s, as applicable, accumulated benefit obligation for its pension plans was $397.6 million and $376.7 million as of December 31, 2014 and 2013, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels.

CPG’s or the Predecessor’s, as applicable, pension plans were underfunded by $46.6 million at December 31, 2014 compared to being underfunded at December 31, 2013 by $32.2 million. The decline in the funded status was due primarily to a decrease in the discount rate from the prior measurement date, the implementation of new mortality assumptions released by the Society of Actuaries in 2014 and decreased employer contributions. CPG contributed $7.7 million and $13.8 million to its pension plans in 2014 and 2013, respectively.

During 2014, CPG’s funded status for its other postretirement benefit plans improved by $10.8 million to an overfunded status of $99.6 million primarily due to favorable asset returns. CPG or the Predecessor, as applicable, contributed approximately $11.9 million and $19.1 million to its other postretirement benefit plans in 2014 and 2013, respectively. No amounts of CPG’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG in 2015.

In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plans’ 2013 service cost plus interest cost and, therefore, settlement accounting was required. As a result, the Predecessor recorded a settlement charge of $13.8 million in 2013. The Predecessor’s net periodic pension benefit cost for 2013 was decreased by $1.3 million as a result of the interim remeasurements.

The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for CPG’s or the Predecessor’s, as applicable, various plans as of December 31.


	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
				*Predecessor*						*Predecessor*
Weighted-average assumptions to determine benefit obligation
Discount Rate		3.64	%		4.34	%		3.96	%		4.76	%
Rate of Compensation Increases		4.00	%		4.00	%		—			—
Health Care Trend Rates
Trend for Next Year		—			—			6.90	%		7.09	%
Ultimate Trend		—			—			4.50	%		4.50	%
Year Ultimate Trend Reached		—			—			2021			2021

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	1% point increase		1% point decrease
	(in millions)
Effect on service and interest components of net periodic cost	$	0.2	$	(0.2	)
Effect on accumulated postretirement benefit obligation		4.1		(3.6	)

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CPG does not expect to make any material contributions to its pension plans in 2015. CPG expects to make contributions to its postretirement medical and life plans totaling $9.9 million in 2015.

The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure CPG’s benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees.


	Pension Benefits		Postretirement Benefits		Other Federal Subsidiary Receipts
	(in millions)
Year(s)
2015	$	23.8	$	9.9	$	0.6
2016		26.4		9.5		0.6
2017		26.1		9.1		0.6
2018		27.1		9.1		0.6
2019		27.3		8.9		0.5
2020-2024		146.9		41.9		2.1

The following table provides the components of the plans’ net periodic benefits cost for each of the three years ended December 31, 2014, 2013, and 2012:


	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
				*Predecessor*			*Predecessor*						*Predecessor*			*Predecessor*
	(in millions)
Components of net periodic benefit
Cost (Income)
Service cost	$	4.8		$	4.9		$	6.0		$	1.1		$	1.5		$	1.5
Interest cost		15.7			14.6			16.9			4.6			5.4			6.6
Expected return on assets		(27.3	)		(25.5	)		(26.2	)		(16.6	)		(13.8	)		(11.8	)
Amortization of prior service (credit) cost		(1.1	)		(1.1	)		(1.1	)		0.1			0.1			0.3
Recognized actuarial loss		7.5			12.3			12.8			—			1.0			0.8

Net Periodic Benefit (Income) Cost	$	(0.4	)	$	5.2		$	8.4		$	(10.8	)	$	(5.8	)	$	(2.6	)
Settlement loss		—			13.8			—			—			—			—

Total Net Periodic Benefit (Income) Cost	$	(0.4	)	$	19.0		$	8.4		$	(10.8	)	$	(5.8	)	$	(2.6	)

The decrease in the actuarially-determined pension benefit (income) cost is due primarily to the settlement loss in 2013 and favorable asset returns in 2014. The actuarially-determined other post-retirement benefit plan income was $10.8 million in 2014 and $5.8 million in 2013.

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The following table provides the key assumptions that were used to calculate the net periodic benefits cost for CPG’s various plans.


	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
				*Predecessor*			*Predecessor*						*Predecessor*			*Predecessor*
Weighted-average assumptions to determine net periodic benefit cost
Discount Rate		4.34	%		3.36	%		4.60	%		4.76	%		3.92	%		4.88	%
Expected Long-Term Rate of Return on Plan Assets		8.30	%		8.30	%		8.30	%		8.14	%		8.17	%		8.22	%
Rate of Compensation Increases		4.00	%		4.00	%		4.00	%		—			—			—

CPG believes it is appropriate to assume an 8.30% rate of return on pension plan assets for its calculation of 2014 pension benefits cost. This is primarily based on asset mix and historical rates of return.

The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability.


	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
				*Predecessor*						*Predecessor*
	(in millions)
Other changes in plan assets and projected benefit obligations recognized in regulatory assets/(liabilities)
Settlements	$	—		$	(13.8	)	$	—		$	—
Net prior service credit		—			—			—			(3.0	)
Net actuarial loss/(gain)		28.9			(43.4	)		11.8			(40.8	)
Less: amortization of prior service cost/(credit)		1.1			1.1			(0.1	)		(0.1	)
Less: amortization of net actuarial gain		(7.5	)		(12.3	)		—			(1.0	)

Total recognized in regulatory assets/(liabilities)	$	22.5		$	(68.4	)	$	11.7		$	(44.9	)

Amount recognized in net periodic benefit cost and regulatory assets/(liabilities)	$	22.1		$	(49.4	)	$	0.9		$	(50.7	)

Based on a December 31 measurement date, the net unrecognized actuarial (gain) loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2015 for the pension plans are $9.4 million, $(1.1) million and zero, respectively, and for other postretirement benefit plans are zero, $0.1 million and zero, respectively.

12.

Fair Value

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.

Long-term debt—affiliated. The fair values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. These fair value

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measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2014 and 2013, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.

The carrying amount and estimated fair values of financial instruments were as follows:


	At December 31,
	Carrying Amount 2014		Estimated Fair Value 2014		Carrying Amount 2013		Estimated Fair Value 2013
					*Predecessor*		*Predecessor*
	(in millions)
Current portion of long-term debt—affiliated	$	115.9	$	120.0	$	—	$	—
Long-term debt—affiliated	$	1,472.8	$	1,550.4	$	819.8	$	835.7

13.

Other Commitments and Contingencies

A. Other Legal Proceedings. In the normal course of its business, CPG has been named as a defendant in various legal proceedings. In the opinion of CPG, the ultimate disposition of these currently asserted claims will not have a material impact on the Company’s consolidated and combined financial statements.

B. Tax Matters. CPG records liabilities for potential income tax assessments. The accruals relate to tax positions in a variety of taxing jurisdictions and are based on CPG’s estimate of the ultimate resolution of these positions. These liabilities may be affected by changing interpretations of laws, rulings by tax authorities, or the expiration of the statute of limitations. CPG’s parent, NiSource, is part of the IRS Large and Mid-Size Business program. As a result, each year’s federal income tax return is typically audited by the IRS. The audits of tax years 2011 and 2012 are in process. In addition, the audits of tax years 2013 and 2014 under the Compliance Assurance Program are also in process. As of December 31, 2014, there were no state income tax audits in progress that would have a material impact on the consolidated and combined financial statements.

CPG is currently being audited for sales and use tax compliance in the state of Louisiana.

C. Environmental Matters. CPG operations are subject to environmental statutes and regulations related to water quality, hazardous waste and solid waste. CPG believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.

It is CPG’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. CPG expects a significant portion of environmental assessment and remediation costs to be recoverable through rates.

As of December 31, 2014 and 2013, CPG or the Predecessor had accrued approximately $14.3 million and $21.4 million, respectively, to cover environmental remediation at various sites. The current portion of this accrual is included in Legal and environmental in the Consolidated and Combined Balance Sheets. The noncurrent portion is included in Other noncurrent liabilities in the Consolidated and Combined Balance Sheets. CPG accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature and extent of contamination, the method of cleanup, and the availability of cost recovery from customers. As of the date of these financial statements, these expenditures are not estimable at some sites. CPG periodically adjusts its accrual as information is collected and estimates become more refined.

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Waste

CPG has cleanup liabilities associated with some of its former operations. Four sites are associated with its former propane operations and ten sites associated with former petroleum operations. The total liability related to these sites was $12.5 million and $12.6 million at December 31, 2014 and 2013, respectively. The liability represents CPG’s best estimate of the cost to remediate the facilities.

Columbia Gas Transmission continues to conduct characterization and remediation activities at specific sites under a 1995 Administrative Order by Consent (subsequently modified in 1996 and 2007) (“AOC”). The 1995 AOC originally covered 245 major facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations and about 3,700 storage well locations. As a result of the 2007 amendment, approximately 50 facilities remain subject to the terms of the AOC. Columbia Gas Transmission utilizes a probabilistic model to estimate its future remediation costs related to the AOC. The model was prepared with the assistance of a third party and incorporates Columbia Gas Transmission and general industry experience with remediating sites. Columbia Gas Transmission completes an annual refresh of the model in the second quarter of each fiscal year. No material changes to the liability were noted as a result of the refresh completed as of June 30, 2014. The total remaining liability at Columbia Gas Transmission related to the facilities subject to remediation was $1.8 million and $8.7 million at December 31, 2014 and 2013, respectively. The liability represents Columbia Gas Transmission’s best estimate of the cost to remediate the facilities or manage the sites. Remediation costs are estimated based on the information available, applicable remediation standards, and experience with similar facilities. Columbia Gas Transmission expects that the remediation for these facilities will be substantially completed in 2015.

On January 31, 2015, the recovery mechanism for PCB remediation costs ceased. Any amounts recovered over amounts incurred will be refunded to customers in association with the final regulatory filing with the FERC, which is expected in May 2015.

D. Operating Lease Commitments. CPG leases assets in several areas of its operations. Payments made in connection with operating leases were $14.9 million in 2014, $13.3 million in 2013 and $10.7 million in 2012, and are primarily charged to operation and maintenance expense as incurred.

Future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are:


	Operating Leases⁽¹⁾
	(in millions)
2015	$	4.7
2016		3.4
2017		5.8
2018		5.5
2019		5.3
After		24.9

Total future minimum payments	$	49.6

(1)

E. Service Obligations. CPG has entered into various service agreements whereby CPG is contractually obligated to make certain minimum payments in future periods. CPG has pipeline service agreements that

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provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2015 to 2025, require CPG to pay fixed monthly charges.

The estimated aggregate amounts of minimum fixed payments at December 31, 2014, were:


	Pipeline Service Agreements
	(in millions)
2015	$	42.7
2016		42.0
2017		38.6
2018		25.9
2019		19.2
After		56.3

Total future minimum payments	$	224.7

14.

Accumulated Other Comprehensive Loss

The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:


	Gains and Losses on Cash Flow Hedges⁽¹⁾			Pension and OPEB Items⁽¹⁾			Accumulated Other Comprehensive Loss⁽¹⁾
	(in millions)
Balance as of January 1, 2012 *— Predecessor*	$	(19.7	)	$	(13.3	)	$	(33.0	)

Other comprehensive income/(loss) before reclassifications		1.0			(4.2	)		(3.2	)
Amounts reclassified from accumulated other comprehensive loss		—			1.1			1.1

Net current-period other comprehensive income/(loss)		1.0			(3.1	)		(2.1	)

Balance as of December 31, 2012 *— Predecessor*	$	(18.7	)	$	(16.4	)	$	(35.1	)

Other comprehensive income before reclassifications		—			6.5			6.5
Amounts reclassified from accumulated other comprehensive loss		1.1			1.7			2.8

Net current-period other comprehensive income		1.1			8.2			9.3

Balance as of December 31, 2013 *— Predecessor*	$	(17.6	)	$	(8.2	)	$	(25.8	)

Other comprehensive loss before reclassifications		—			(9.3	)		(9.3	)
Amounts reclassified from accumulated other comprehensive loss		1.0			(0.4	)		0.6

Net current-period other comprehensive income/(loss)		1.0			(9.7	)		(8.7	)

Balance as of December 31, 2014	$	(16.6	)	$	(17.9	)	$	(34.5	)

(1)	All amounts are net of tax. Amounts in parentheses indicate debits.

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Equity Method Investment

During 2008, Millennium Pipeline, in which CPG has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties. During August 2010, Millennium Pipeline completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million, $375.0 million at 5.33% due June 30, 2027 and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium Pipeline repaid all outstanding borrowings under its credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were primarily accounted for as cash flow hedges by Millennium Pipeline. As an equity method investment, CPG is required to recognize a proportional share of Millennium Pipeline’s other comprehensive income. The remaining proportional share of unrecognized loss of $16.6 million, net of tax, related to these terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $16.6 million and $17.6 million at December 31, 2014 and December 31, 2013, respectively, is included in unrealized losses on cash flow hedges above.

15.

Other, Net


	Year Ended December 31,
	2014			2013		2012
				*Predecessor*		*Predecessor*
	(in millions)
AFUDC Equity	$	11.0		$	6.8	$	1.4
Miscellaneous⁽¹⁾		(2.2	)		11.1		0.7

Total Other, net	$	8.8		$	17.9	$	2.1

(1)	Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.

16.

Segments of Business

Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The NiSource Chief Executive Officer is the chief operating decision maker for the periods presented.

At December 31, 2014, CPG’s operations comprise one operating segment. CPG’s segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services and development of mineral rights positions.

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17.

Supplemental Cash Flow Information

The following table provides additional information regarding CPG’s Statements of Consolidated and Combined Cash Flows for the years ended December 31, 2014, 2013 and 2012:


	Year Ended December 31,
	2014		2013		2012
			*Predecessor*		*Predecessor*
	(in millions)
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities	$	78.5	$	53.1	$	77.2
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	53.6	$	38.4	$	30.4
Cash paid for income taxes		21.2		15.3		73.3

18.

Concentration of Credit Risk

Columbia Gas of Ohio, an affiliated party, accounted for greater than 10% of total operating revenues in the years ended December 31, 2014, 2013 and 2012. Washington Gas and Light, a non-affiliated entity, accounted for greater than 10% of total operating revenues in the year ended December 31, 2012. The following table provides the customer operating revenues and the customer operating revenues as a percentage of total operating revenues for the years ended December 31, 2014, 2013 and 2012:


	2014					2013					2012
	Total Operating Revenues		Percentage of Total Operating Revenues			Total Operating Revenues		Percentage of Total Operating Revenues			Total Operating Revenues		Percentage of Total Operating Revenues
						*Predecessor*					*Predecessor*
	(in millions)
Columbia Gas of Ohio	$	168.5		12.5	%	$	167.5		14.2	%	$	172.4		17.2	%
Washington Gas and Light		116.1		8.6	%		104.6		8.9	%		107.1		10.7	%

There was no other single customer that accounted for greater than 10% of total operating revenues during 2014, 2013 or 2012. The loss of a significant portion of operating revenues from either of these customers would have a material adverse effect on the business of CPG.

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19.

Discontinued Operations

There were no assets and liabilities of discontinued operations and held for sale on the Consolidated and Combined Balance Sheets at December 31, 2014 and 2013.

Results from discontinued operations are provided in the following table. These results are primarily from fulfilling obligations related to the sale of CPG’s former exploration and production subsidiary in 2003 and Columbia Propane Corporation in 2001. There were no significant remaining liabilities related to these transactions at December 31, 2014.


	Year Ended December 31,
	2014			2013		2012
				*Predecessor*		*Predecessor*
	(in millions)
Income (loss) from discontinued operations	$	(0.9	)	$	14.5	$	(3.6	)
Income tax expense (benefit)		(0.3	)		5.5		(1.4	)
Income (Loss) from Discontinued Operations—net of taxes	$	(0.6	)	$	9.0	$	(2.2	)

20.

Subsequent Event

Closing of Initial Public Offering. On February 11, 2015, the MLP completed its initial public offering of 53,833,107 common units representing limited partnership interests, constituting approximately 53.5% of the MLP’s outstanding limited partnership interests. The MLP received approximately $1,170.0 million of net proceeds from the initial public offering. CEG owns the general partner of the MLP, all of the MLP’s subordinated units and all of the MLP’s incentive distribution rights. The assets of the MLP consist of a 15.7% limited partner interest in Columbia OpCo, which consists of substantially all of the Columbia Pipeline Group Operations segment of NiSource.

In conjunction with the closing of the initial public offering, the MLP’s $500.0 million senior revolving credit facility became effective. Of this credit facility, $50.0 million is available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures and the funding of capital calls. Indebtedness under the MLP credit facility ranks equally with all of the MLP’s outstanding unsecured and unsubordinated debt. NiSource, CEG, OpCo GP, CPG and Columbia OpCo have each fully guaranteed the MLP credit facility, except that NiSource will be released from its guarantee upon receipt by CPG of a rating by Moody’s and S&P.

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