10-K 1 a06-1876_110k.htm ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-3551

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

PENNSYLVANIA		25-0464690
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

225 North Shore Drive
Pittsburgh, Pennsylvania		15212
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (412) 553-5700

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, no par value		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act).

Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter periods that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b–2 of the Act).

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No ý

The aggregate market value of voting stock held by non-affiliates of the registrant
as of June 30, 2005: $4,062,941,316

The number of shares outstanding of the issuer’s classes of common stock
as of January 31, 2006: 119,849,572

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III, portions of Items 10, 11, 12, and 14 are incorporated by reference from the Proxy Statement for the Company’s Annual Meeting of Stockholders to be held on April 12, 2006, which Proxy Statement will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2005, except for the Stock Performance Graph, Report of the Compensation Committee on Executive Compensation, and Report of the Audit Committee.

TABLE OF CONTENTS

	Glossary of Commonly Used Terms, Abbreviations, and Measurements

PART I

Item 1	Business
Item 1A	Risk Factors
Item 1B	Unresolved Staff Comments
Item 2	Properties
Item 3	Legal Proceedings
Item 4	Submission of Matters to a Vote of Security Holders
	Executive Officers of the Registrant

PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6	Selected Financial Data
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A	Quantitative and Qualitative Disclosures About Market Risk
Item 8	Financial Statements and Supplementary Data
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A	Controls and Procedures
Item 9B	Other Information

PART III

Item 10	Directors and Executive Officers of the Registrant
Item 11	Executive Compensation
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13	Certain Relationships and Related Transactions
Item 14	Principal Accounting Fees and Services

PART IV

Item 15	Exhibits, Financial Statement Schedules
	Index to Financial Statements Covered by Report of Independent Registered Public Accounting Firm
	Index to Exhibits
	Signatures
	Certifications

Glossary of Commonly Used Terms, Abbreviations, and Measurements

Commonly Used Terms

Appalachian Basin – The area of the United States comprised of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie at the foot of the Appalachian Mountains.

basis – When referring to natural gas, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location and contract pricing.

Btu – One British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

cash flow hedge – A derivative instrument that complies with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

collar – A financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

development well – A well drilled into a known producing formation in a previously discovered field.

exploratory well – A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

farm tap – Natural gas supply service in which the customer is served directly from a well or gathering pipeline.

futures contract – An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gas – All references to “gas” in this report refer to natural gas.

gross – “Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.

heating degree days – Measure used to assess weather’s impact on natural gas usage calculated by adding the difference between 65 degrees Fahrenheit and the average temperature of each day in the period (if less than 65 degrees Fahrenheit). Each degree by which the average temperature falls below 65 degrees Fahrenheit represents one heating degree day.

hedging – The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.

margin deposits – Funds or good faith deposits posted during the trading life of a futures contract to guarantee fulfillment of contract obligations.

margin call – A demand for additional or variation margin deposits when futures prices move adversely to a hedging party’s position.

net – “Net” gas and oil wells or “net” acres are determined by summing the fractional ownership working interests the Company has in gross wells or acres.

proved reserves – Reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reserves under existing economic and operating conditions.

proved developed reserves – Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

reservoir – A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

transportation – Moving gas through pipelines on a contract basis for others.

throughput – Total volumes of natural gas sold or transported by an entity.

working interest – An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

Abbreviations

APB No. 18 – Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”

APB No. 25 – Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”

EITF No. 02-3 – Emerging Issues Task Force No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17”

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

FSP FAS 106-2 – FASB Staff Position 106-2, “Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003”

FIN 45 – FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34”

IRC – Internal Revenue Code of 1986

IRS – Internal Revenue Service

NYMEX – New York Mercantile Exchange

OTC – Over the Counter

PA PUC – Pennsylvania Public Utility Commission

SEC – Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

SFAS No. 19 – Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”

SFAS No. 69 – Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Natural Gas Producing Activities”

SFAS No. 71 – Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”

SFAS No. 87 – Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”

SFAS No. 88 – Statement of Financial Accounting Standards No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”

SFAS No. 106 – Statement of Financial Accounting Standards No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”

SFAS No. 109 – Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”

SFAS No. 115 – Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”

SFAS No. 123 – Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”

SFAS No. 123(R) – Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment”

SFAS No. 128 – Statement of Financial Accounting Standards No. 128, “Earnings Per Share”

SFAS No. 133 – Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended

SFAS No. 143 – Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”

SFAS No. 144 – Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS No. 146 – Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”

SFAS No. 148 – Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation –Transition and Disclosure – an amendment of FASB Statement No. 123”

Measurements

Bbl = barrel

Bcf = billion cubic feet

Bcfe = billion cubic feet of natural gas equivalents

Mcf = thousand cubic feet

Mcfe = thousand cubic feet of natural gas equivalents

MMBtu = million British thermal units

MMcf = million cubic feet

MMcfe = million cubic feet of natural gas equivalents

PART I

Item 1. Business

Forward-Looking Statements

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling and infrastructure development programs, production volumes, reserves, capital expenditures and earnings. A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors.”

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

General

In this Form 10-K, references to “we,” “us,” “our,” “Equitable,” “Equitable Resources” and “the Company” refer collectively to Equitable Resources, Inc. and its consolidated subsidiaries, unless otherwise specified.

Equitable Resources, Inc. is an integrated energy company, with an emphasis on Appalachian area natural gas supply activities including production and gathering and natural gas distribution and transmission. The Company and its subsidiaries offer energy (natural gas, and a limited amount of natural gas liquids and crude oil) products and services to wholesale and retail customers through two business segments: Equitable Utilities and Equitable Supply. In December 2005, the Company discontinued and sold the operations of its NORESCO segment, which provides energy efficiency solutions to customers including governmental, military, institutional, commercial and industrial end-users.

The Company was formed under the laws of Pennsylvania by the consolidation and merger in 1925 of two constituent companies, the older of which was organized in 1888. In 1984, the corporate name was changed to Equitable Resources, Inc.

The Company and its subsidiaries had approximately 1,250 employees at the end of 2005, of which 364 employees were subject to collective bargaining agreements. Although one union representing 13 employees has been operating without a contract since April 19, 2004, the Company believes that its employee relations are generally good.

The Company makes certain filings with the SEC, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqt.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The Company’s annual reports to shareholders, press releases and recent analyst presentations are also available on the Company’s website.

Business Segments

Equitable Utilities

Equitable Utilities’ operations comprise the gathering, transportation, storage, distribution and sale of natural gas. Equitable Utilities has both regulated and nonregulated operations. The regulated group consists of the Company’s federally-regulated pipeline and storage operations and the state-regulated distribution operations, while the nonregulated group is involved in the non-jurisdictional marketing of natural gas, risk management activities for the Company and the sale of energy-related products and services. Equitable Utilities generated approximately 34% of the Company’s net operating revenues in 2005.

Distribution Operations

Equitable Utilities’ Distribution Operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales, also referred to as farm tap service, in eastern Kentucky and West Virginia. The Distribution Operations provide natural gas services to approximately 274,400 customers, comprising 255,600 residential customers and 18,800 commercial and industrial customers. Equitable Gas purchases gas through supply contracts from various sources including major and independent producers in the Gulf Coast, local producers in the Appalachian area and gas marketers (including an affiliate). Equitable Gas’ supply purchases include various pricing mechanisms, ranging from fixed prices to several different index-related prices.

Equitable Utilities’ distribution rates, terms of service, contracts with affiliates and issuance of securities are subject to comprehensive regulation by the PA PUC and the Public Service Commission of West Virginia. The field line sales rates in Kentucky are also subject to rate regulation by the Kentucky Public Service Commission. Equitable Gas also operates a small gathering system in Pennsylvania, which is not subject to comprehensive regulation.

In most cases, the Company must seek approval of one or more of these regulatory bodies prior to increasing (or decreasing) its rates. Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and is allowed to recover a return in addition to its costs of operations. However, the Company’s regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term. Equitable Gas has worked with, and continues to work with regulators to implement alternative performance-based rates. Equitable Gas’ tariffs for industrial and commercial customers allow for negotiated rates in appropriate circumstances. Equitable Gas has not filed a rate case since 1997, and its predominant approach to maximizing profits is cost control. Regulators periodically audit the Company’s compliance with applicable regulatory requirements. The Company is not aware of any significant non-compliance as a result of any completed audits.

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 72% of calendar year 2005 revenues occurring during the winter heating season (the months of January, February, March, November and December). Significant quantities of purchased natural gas are placed in underground storage inventory during off-peak season to accommodate higher demand during the winter heating season.

The Distribution Operations’ service territory is a relatively small geographic area, with a high percentage of gas users within a static population and economy. Management believes there are limited continuing growth opportunities in the service area, where competition exists with two other major local distribution companies.

Pipeline (Transportation and Storage) Operations

Equitable Utilities’ interstate pipeline operations are carried out by Equitrans, L.P. (Equitrans). These operations offer gas gathering, transportation, storage and related services to affiliates and third parties in the northeastern United States including, but not limited to, Dominion Resources, Inc., Keyspan Corporation, NiSource, Inc., PECO Energy Company and Amerada Hess Corporation. In 2005, approximately 76% of transportation volumes and approximately 80% of transportation revenues were from affiliates.

Equitrans’ rates are subject to regulation by the FERC. Throughout 2004 and 2005, Equitrans has filed multiple rate case applications with the FERC which have been consolidated and seek to resolve several issues including establishing an appropriate return on the Company’s capital investments, the Company’s pension funding levels and accruing for post-retirement benefits other than pensions. A comprehensive and unopposed settlement to the consolidated rate case was submitted to the FERC on December 9, 2005. The settlement, if approved by the FERC, will allow the Company to fully recover its cost of providing service, including the recovery of fuel and lost and unaccounted-for gas, provide for the replenishment of migrated storage base gas, increase service flexibility and improve the Company’s ability to recover costs associated with maintaining pipeline integrity. Equitrans began charging the proposed rates, subject to refund, during the second half of 2004, consistent with orders issued by the FERC. Accordingly, Equitrans has established a reserve, which will be adjusted upon ultimate resolution of the consolidated rate case. The Company is awaiting a FERC order with respect to the settlement. While the Company expects that approval of the settlement agreement as filed will enable the Company to realize benefits in the future, the immediate impact on pipeline operating income is not expected to be significant.

While all of Equitrans’ firm transportation contracts are currently set to expire in either 2006 or 2007, the Company anticipates that the majority of the related volumes will be fully subscribed, and therefore, any resulting decrease in operating income is not expected to be significant.

Energy Marketing

Equitable Utilities’ unregulated marketing operations include the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, LLC (Equitable Energy), and the sale of energy-related products and services by Equitable Homeworks, LLC. Services and products offered by the marketing operations include commodity procurement, delivery and storage, risk management and customer services for energy consumers including large industrial, utility, commercial and institutional end-users. Equitable Energy also engages in trading and risk management activities for the Company. The objective of these activities is to limit the Company’s exposure to shifts in market prices and to optimize the use of the Company’s assets.

The marketing operations are subject to regulation by the U.S. Commodity Futures Trading Commission, the FERC and the PA PUC.

Equitable Supply

Equitable Supply’s production business develops, produces and sells natural gas and, to a limited extent, crude oil and natural gas liquids, in the Appalachian region of the United States. Its gathering business consists of gathering the Company’s and third party gas and the processing of natural gas liquids. Equitable Supply generated approximately 66% of the Company’s net operating revenues in 2005.

Production

Equitable Supply’s production business, operating through Equitable Production Company and several smaller affiliates (collectively referred to as “Equitable Production”), is among the largest owners of proved natural gas reserves in the Appalachian Basin. Equitable Production currently operates approximately 12,000 producing wells in the Appalachian Basin.

The Company’s reserves are located entirely in the Appalachian Basin. The Appalachian Basin is characterized by wells with comparatively low rates of annual decline in production (wells generally produce for periods longer than 50 years), low production costs per well and high energy content. Once drilled and completed, wells in the Appalachian Basin typically have low ongoing operating and maintenance requirements. Many of the Company’s wells have been producing for decades, and in some cases since the early 1900’s. Management believes that virtually all of the Company’s wells are low risk development wells in part because they are drilled in areas known to be relatively productive and to relatively shallow depths ranging from 1,000 to 7,000 feet below the surface. Many of these wells are completed in more than one producing formation, including coal formations in certain areas, and production from these formations may be commingled.

In 2005, Equitable Production drilled 455 gross wells (345 net wells) at a success rate of nearly 100%. Drilling was concentrated within Equitable’s core areas of southwestern Virginia, southeastern Kentucky and southern West Virginia. This activity resulted in an average of 17.2 MMcf per day of gas sales and proved developed reserve additions of approximately 100 Bcfe. The 100 Bcfe of proved developed reserve additions include approximately 30 Bcfe of proved developed extensions, discoveries and other additions that were not previously classified as undeveloped. The remaining 70 Bcfe of proved developed reserve additions relate to proved undeveloped reserves that were transferred to proved developed reserves.

Equitable Supply does not actively engage in activities to differentiate its products and therefore receives market-based pricing. The market price for gas located in the Appalachian Basin is generally higher than the price for gas located in the Gulf Coast, however, because of the relative differences in the supply of and demand for natural gas in those areas and in the relative cost to transport to customers in the northeastern United States. As a consequence, Equitable Production’s location provides a price advantage over companies located in the Gulf Coast region of the country.

The Company has noticed some relative value erosion of Mid-Atlantic basis as a result of new base load gas supplies. If the rate of supply growth in Appalachia exceeds the Mid-Atlantic region’s growth in demand, there may be further weakening in basis, especially in the summer months. At this time, this erosion has not had a significant impact on the Company’s results.

The combination of long-lived production, low drilling costs, high drilling completion rates at shallow depths and proximity to natural gas markets has resulted in a highly fragmented operating environment in the Appalachian Basin. Natural gas drilling activity has increased as suppliers in the Appalachian Basin attempt to take advantage of higher than normal natural gas prices. While increased activity can place constraints on capacity of labor, equipment, pipeline availability and other resources in the Appalachian Basin, it also provides opportunities for expansion of natural gas gathering activities and potential for higher quality rigs and labor providers in the future.

Equitable Supply hedges a portion of its forecasted natural gas production and third party purchases and sales at specified prices for a specified period of time. The Company’s hedging strategy and information regarding its derivative instruments are outlined in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 3 to the Consolidated Financial Statements.

Gathering

Equitable Gathering derives its revenues from charges it assesses to customers on a gathering and production pipeline system in the Appalachian Basin. As of December 31, 2005, the system included approximately 8,500 miles of pipeline located throughout West Virginia, eastern Kentucky, southwestern Virginia and portions of Pennsylvania. Over 80% of the volumes through the pipeline system interconnect with three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission. The gathering system also maintains interconnects with Equitrans, the Company’s interstate transmission affiliate that affords access to natural gas markets in southwestern Pennsylvania and the northeastern United States. Maintaining these interconnects provides the Company with access to multiple markets and the flexibility to redirect deliveries when flow interruptions occur.

Gathered sales volumes for 2005 totaled 121.0 Bcf, of which approximately 57% related to the gathering of Equitable Production’s sales volumes, 34% related to third party volumes, and the remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee. Approximately 80% of the Company’s 2005 gathering revenues were from affiliates. Effective January 1, 2005, the Company reorganized its businesses in order to better identify the operating and capital costs associated with the gathering business. The information derived from this reorganization and upward pressure on operating costs resulting from the expansion of activity in the Appalachian Basin have led Equitable Gathering to determine that it is, in many cases, currently charging gathering rates which are below its cost of service. Equitable Gathering will pursue full recovery of its costs of providing services by increasing the rates charged to its customers.

Certain portions of the gathering system are subject to rate regulation by the FERC and the Company has sought to have rates established for those gathering systems as part of the consolidated rate case described under

“Equitable Utilities – Pipeline (Transportation and Storage) Operations.” The consolidated rate case includes the operations of gathering facilities that were recorded in Equitable Supply’s gathering operations during 2005, 2004 and 2003. Effective January 1, 2006, these gathering systems, which consist of 1,400 miles of pipeline and related facilities with approximately 13.3 Bcf of annual throughput, were transferred to Equitable Utilities for segment reporting purposes. The effect of the transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Supply segments; segment results have not been restated for this transfer.

Competition in natural gas gathering is based mainly on gathering system capacity, price and location. Key competitors in Equitable Supply’s gathering operations include independent gas gatherers and integrated Appalachian energy companies. See “Outlook” under Equitable Supply’s section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussion of the Company’s strategy in regards to its midstream gathering operations.

Discontinued Operations

In December 2005, the Company sold the domestic operations of its NORESCO business segment for $82 million before customary purchase price adjustments of $2 million, which resulted in the Company receiving $80 million of proceeds in December 2005 for this sale. The sales price is also subject to future customary purchase price adjustments per the terms of the agreement. Also in December 2005, the Company entered into a purchase and sale agreement, subject to closing conditions, to sell the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited for $2.5 million. This sale is expected to close in 2006 and as such, the Company considers the investment to be held for sale. As a result of these transactions, the Company has reclassified its financial statements for all periods presented to reflect the operating results of the NORESCO segment as discontinued operations.

Composition of Segment Operating Revenues

Presented below are operating revenues as a percentage of total operating revenues for each class of products and services representing greater than 10% of total operating revenues during the years 2003 through 2005.

	2005		2004		2003
Equitable Utilities:
Residential natural gas sales	26	%	29	%	32	%
Marketed natural gas	27	%	23	%	18	%
Equitable Supply:
Produced natural gas equivalents	30	%	29	%	28	%

Financial Information About Segments

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to the Consolidated Financial Statements for financial information by business segment.

Financial Information About Geographic Areas

Substantially all of the Company’s assets and operations are located in the continental United States.

Environmental

See Note 19 to the Consolidated Financial Statements for information regarding environmental matters.

Item 1A. Risk Factors

Risks Relating to Our Business

In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business. Please note that additional risks not presently known to the Company or that are currently considered immaterial may also have a negative impact on the Company’s business and operations.

Natural gas price volatility may have an adverse effect on our revenue, profitability and liquidity.

Our revenue, profitability and liquidity depend on the price and demand for natural gas. The markets for natural gas are volatile and fluctuations in prices will affect our financial results. Recently, natural gas prices have increased substantially. Such price increases have subjected us, and may continue to subject us to, margin calls which require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral, which is interest-bearing, provided to our hedge counterparties is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related hedged transaction. Increases in natural gas prices may also be accompanied by or result in increased well drilling costs, increased deferral of purchased gas costs for our distribution operations, increased production taxes, increased lease operating expenses, increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from our distribution customers and increased customer conservation or conversion to alternative fuels. Lower natural gas prices, increases in our estimates of development costs or changes to our production assumptions may result in our having to make downward adjustments to our estimated proved reserves and incur non-cash charges to earnings. Natural gas prices are affected by a number of factors beyond our control, which include: weather conditions; the supply of and demand for natural gas; national and worldwide economic and political conditions; the price and availability of alternative fuels; the proximity to, and availability of capacity on, transportation facilities; and government regulations, such as regulation of natural gas transportation, royalties and price controls.

We are dependent on our ability to cost-effectively access capital markets. Our inability to obtain capital on acceptable terms may adversely affect our business. A reduction in our debt issuer credit ratings could increase our borrowing costs.

We rely on access to both short-term debt markets and longer-term capital markets as a source of liquidity and to satisfy our capital requirements in excess of cash flow from our operations. Each of the agencies who periodically assign credit ratings on our debt has stated that our rating is based on their expectations with respect to certain financial performance measures and ratios. A rating may be subject to revision or withdrawal at any time by the assigning credit rating agency. Any inability to maintain our current credit ratings could affect, especially during times of uncertainty in the capital markets, our ability to raise capital on favorable terms which, in turn, could impact our ability to manage our business. Any downgrades in these ratings could have a negative impact on our liquidity, our access to capital markets and our costs of financing and could increase the amount of collateral required by our hedge counterparties. Capital market disruptions could also adversely affect our ability to access one or more financial markets.

Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.

Significant portions of our gathering, transportation, storage and distribution businesses are subject to state and federal regulation including regulation of the rates which we may assess our customers. The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate. These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals. Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of

hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, restoration of drilling properties after drilling is completed, pipeline safety and work practices related to employee health and safety. Complying with these requirements could have a significant effect on our costs of operations and competitive position.

The rates of federal, state and local taxes applicable to the industries in which we operate, including production taxes paid by Equitable Supply, which often fluctuate, could be increased by the respective taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change. Any such increase or change could adversely impact our cash flows and profitability.

The actual quantities and present value of our proved gas reserves may prove to be lower than we have estimated, which could negatively impact our long-term growth prospects.

The proved gas reserve information included in this Form 10-K represents only estimates calculated using gas prices in effect on the date indicated in the reports. Any significant price changes will have a material effect on the present value of our reserves. For example, an increase in gas prices of approximately $0.50 per Mcfe from those prices used to calculate our reserves would increase the present value of our proved reserves by approximately $322 million, and the same decrease in gas prices would decrease the present value of our proved reserves by the same amount.

Estimating underground accumulations of gas involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain which could cause a revision to our future reserve estimates. Estimates of economically recoverable gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas and the assumed effects of regulations by governmental agencies. Some of these assumptions, including the 10% discount factor used to calculate discounted future net reserves in this Form 10-K, are required by the SEC.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of gas that are ultimately recovered, the timing of the recovery of gas reserves, the production and operating costs incurred, the amount and timing of future development expenditures and the gas price received.

The amount and timing of actual future gas production and the cost and timing of our infrastructure development program are difficult to predict and may vary significantly from our estimates which may reduce our earnings.

Our future success depends on our ability to develop additional gas reserves that are economically recoverable and to transport the production from those reserves to market, and our failure to do so may reduce our earnings. In 2005, we expanded our drilling program, and we have subsequently announced further expansion. We have also announced a significant investment in transportation infrastructure (the Big Sandy Pipeline) which is intended to address a lack of capacity on and access to existing transportation pipelines as well as curtailments on such pipelines. Our drilling of development wells and our infrastructure development program can involve significant risks, including those related to timing and cost overruns and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. In addition, we may not be able to obtain sufficient third party transportation contracts to recover the costs of our infrastructure development program. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Without continued successful development or acquisition activities, our reserves and revenues will decline as a result of our current reserves being depleted by production.

Our operations are weather sensitive.

Weather conditions directly influence the demand for natural gas, affect the price of energy commodities and may hinder our gathering, transportation and drilling operations. For example, mild winter temperatures can cause a

decrease in the volume or affect the price of gas we sell in any year and colder winter temperatures can cause an increase in the amount or in the price of gas we sell in any year. In addition, severe weather, including hurricanes, can be destructive, causing natural gas prices to be volatile, our drilling operations to be curtailed, delayed or canceled, our gathering and transportation assets to be damaged and our operating expenses to increase.

We are subject to operating and litigation risks that may not be covered by insurance.

Our business’ operations are subject to all of the inherent hazards and risks normally incidental to the production, transportation, storage and distribution of natural gas. 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. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that insurance policies we maintain to limit our liability of such losses will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that such levels of insurance will be available in the future at economical prices.

We may engage in acquisition and disposition strategies that involve a number of inherent risks, any of which may cause us not to realize anticipated benefits and may adversely affect our earnings, cash flows and results of operations.

We intend to continue to strategically position our business in order to improve our ability to compete. Acquisitions, joint ventures and other business combinations involve various inherent risks, such as assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates; the potential loss of key personnel of an acquired business; our ability to achieve identified financial and operating synergies anticipated to result from an acquisition or other transaction; and unanticipated changes in business and economic conditions affecting an acquisition or other transaction. We may be unable to realize, or do so within any particular time frame, the cost reductions, cash flow increases or other synergies expected to result from such transactions. In addition, various factors including prevailing market conditions and the incursion of related contingent liabilities could negatively impact the benefits we receive from disposition transactions.

If we fail to achieve our strategic or financial goals in any acquisition or disposition transaction, it could have a significant adverse affect on our earnings, cash flows and results of operations. Furthermore, if we borrow money to finance an acquisition, our failure to achieve our stated goals could impact our ability to repay such borrowings or other borrowings and could weaken our financial condition.

See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for further discussion regarding the Company’s exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.

Item 1B. Unresolved Staff Comments

There are no comments regarding any of the Company’s periodic or current reports filed under the Securities Exchange Act of 1934 that were received from the SEC staff more than 180 days before the fiscal year-end covered by this Form 10-K that remain unresolved at the time of this filing.

Item 2. Properties

Principal facilities are owned by the Company’s business segments, with the exception of various office locations and warehouse buildings, which are leased. A limited amount of equipment is also leased. The majority of the Company’s properties are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, or occupied under perpetual easements or other rights acquired for the most part without examination of underlying land titles. The Company’s facilities are generally well maintained and, where necessary, are replaced or expanded to meet operating requirements.

Headquarters. In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building, which the Company leases, located at the North Shore in Pittsburgh, Pennsylvania. As a result of this consolidation, the Company still maintains leases for properties previously used for its administrative operations that are not currently being utilized. The Company is actively searching for tenants to sublease these properties from the Company.

Equitable Utilities. This segment owns and operates natural gas distribution properties as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The segment also owns and operates underground storage, transmission and gathering facilities in Pennsylvania and West Virginia.

The distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky. The interstate pipeline operations consist of approximately 1,500 miles of transmission, storage, and gathering lines and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. Equitrans has 15 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 57 Bcf of storage capacity of which 27 Bcf is working gas. These storage reservoirs are clustered, with 8 in northern West Virginia and 7 in southwestern Pennsylvania.

Equitable Supply. This segment currently has an inventory of approximately 3.3 million gross acres, approximately 72% of which is considered undeveloped, which encompasses nearly all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties. As of December 31, 2005, the Company estimated its total proved reserves to be 2,365 Bcfe, including proved undeveloped reserves of 692 Bcfe from approximately 2,515 gross proved undeveloped drilling locations (2,292 net proved undeveloped drilling locations) on properties the Company either owns or in which it holds a leasehold interest. No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves. Additional information relating to the Company’s estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 25 (unaudited) to the Consolidated Financial Statements. The gathering operations owns and operates approximately 8,500 miles of gathering pipelines and 179 compressor units comprising 109 compressor stations with approximately 117,000 horse power of installed capacity, as well as other general property and equipment. This segment’s production and gathering properties are located in the Appalachian Basin, specifically Kentucky, Pennsylvania, Virginia and West Virginia.

Natural Gas and Crude Oil Production:

	2005		2004		2003
Natural Gas:
MMcf produced	78,105		72,226		69,422
Average well-head sales price per Mcfe sold (net of hedges)	$	5.13	$	4.45	$	3.91
Crude Oil:
Thousands of Bbls produced	108		83		83
Average sales price per Bbl	$	53.07	$	37.38	$	26.08

Average production cost, including severance taxes (lifting cost), of natural gas and crude oil during 2005, 2004, and 2003 was $0.771, $0.583, and $0.499 per Mcfe, respectively.

	Natural Gas	Oil
Total productive wells at December 31, 2005:
Total gross productive wells	11,932	23
Total net productive wells	8,991	18

Total acreage at December 31, 2005:
Total gross productive acres		917,080
Total net productive acres		862,055
Total gross undeveloped acres		2,403,302
Total net undeveloped acres		2,249,544

Number of net productive and dry exploratory and development wells drilled:

	2005	2004	2003
Exploratory wells:
Productive	—	—	—
Dry	—	—	—
Development wells:
Productive	344.2	246.5	354.8
Dry	1.0	—	—

Substantially all of Equitable Supply’s sales are delivered to several large interstate pipelines on which the Company leases capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.

Equitable Supply leases office space in Charleston, West Virginia. The segment also leases compressors in West Virginia, Virginia and Kentucky and other office space and equipment in Pennsylvania, West Virginia, Virginia and Kentucky that is not significant to the operation of the segment.

Item 3. Legal Proceedings

In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2005.

Executive Officers of the Registrant (as of February 22, 2006)

Name and Age	Current Title (Year Initially Elected an Executive Officer)	Business Experience

John A. Bergonzi (53)	Vice President and Corporate Controller (January 2003)	Elected to present position January 2003; Corporate Controller and Assistant Treasurer from December 1995 to December 2002.

Philip P. Conti (46)	Vice President and Chief Financial Officer (August 2000)	Elected to present position January 2005, also Treasurer until January 2006; Vice President, Finance and Treasurer from August 2000 to January 2005.

Randall L. Crawford (43)	Vice President (January 2003)	Elected to present position January 2003; President, Equitable Gas Company from January 2003 to present; Executive Vice President, Equitable Gas Company from November 2000 to December 2002.

Murry S. Gerber (52)	Chairman, President and Chief Executive Officer (June 1998)	Elected to present position May 2000; President and Chief Executive Officer from June 1, 1998 to present.

Joseph E. O’Brien (53)	Vice President (January 2001)	Elected to present position January 2001; President, NORESCO, LLC from January 2000 to June 2005.

Johanna G. O’Loughlin (59)	Senior Vice President, General Counsel and Secretary (December 1996)	Elected to present position January 2002; Vice President, General Counsel and Secretary from May 1999 to January 2002.

Charlene Petrelli (44)	Vice President, Human Resources (January 2003)	Elected to present position January 2003; Director of Corporate Human Resources from October 2000 to December 2002.

David L. Porges (48)	Vice Chairman and Executive Vice President, Finance and Administration (July 1998)	Elected to present position January 2005; Executive Vice President and Chief Financial Officer from February 2000 to January 2005.

Diane L. Prier (46)	Vice President (December 2004)	Elected to present position December 2004; President, Equitable Production Company from December 2004 to present; President, Williams Alaska Petroleum, Inc. (a subsidiary of The Williams Companies, a company engaged in natural gas gathering, storage, processing and transportation, as well as oil and gas exploration and production) from August 2001 to April 2004; Vice President - Rockies Midstream Operations, The Williams Companies from March 1998 to July 2001.

Messrs. Gerber and Porges have executed employment agreements with the Company. All executive officers serve at the pleasure of the Company’s Board of Directors. Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company’s common stock is listed on the New York Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions, and the dividends declared and paid per share, are summarized as follows (in U.S. dollars per share):

	2005 (a)						2004 (a)
	High		Low		Dividend		High		Low		Dividend
1^st Quarter	$	30.62	$	27.89	$	0.19	$	22.46	$	21.05	$	0.15
2^nd Quarter	34.42		28.16		0.21		25.88		22.00		0.19
3^rd Quarter	39.90		34.01		0.21		27.25		24.95		0.19
4^th Quarter	41.18		34.51		0.21		30.59		26.68		0.19

(a) Adjusted to reflect the two-for-one stock split effective September 1, 2005.

As of February 15, 2006, there were 4,182 shareholders of record of the Company’s common stock.

The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Company’s results of operations and financial condition and other factors. Based on currently foreseeable market conditions, the Company anticipates that comparable dividends will be paid on a regular quarterly basis.

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2005.

Period	Total number of shares (or units) purchased (a)	Average price paid per share		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (b)

October 2005 (October 1 – October 31)	3,591	$	36.57	—	9,385,400

November 2005 (November 1 – November 30)	423,483	$	37.57	418,200	8,967,200

December 2005 (December 1 – December 31)	1,055,036	$	37.35	581,800	8,385,400

Total	1,482,110			1,000,000

(a) Includes 469,685 shares withheld to cover tax withholdings in connection with the December 2005 payout of all amounts previously deferred and accrued in the Equitable Resources, Inc. Employee Deferred Compensation Plan and Equitable Resources, Inc. 2005 Employee Deferred Compensation Plan and 12,425 shares for Company-directed purchases made by the Company’s 401(k) plans. All other purchases were open market purchases made pursuant to the Company’s publicly disclosed repurchase program. The Company periodically enters into “10b5-1 plans,” or trading plans, to allow for continuance of its share repurchase program through earnings and other blackout periods.

(b) Equitable’s Board of Directors previously authorized a share repurchase program with a maximum of 50.0 million shares and no expiration date. The program was initially publicly announced on October 7, 1998, with subsequent amendments announced on November 12, 1999, July 20, 2000, April 15, 2004, and July 13, 2005.

Item 6. Selected Financial Data

	As of and for the year ended December 31, (a)
	2005		2004		2003		2002		2001
	(Thousands, except per share amounts)

Operating revenues	$	1,253,724	$	1,045,183	$	876,574	$	878,961	$	951,955
Income from continuing operations before cumulative effect of accounting change (b)	$	258,574	$	298,790	$	165,750	$	145,731	$	149,483
Income from continuing operations before cumulative effect of accounting change per share of common stock (c)
Basic	$	2.14	$	2.42	$	1.34	$	1.16	$	1.16
Diluted	$	2.09	$	2.37	$	1.31	$	1.14	$	1.13
Total assets	$	3,342,285	$	3,205,346	$	2,948,073	$	2,440,396	$	2,520,078
Long-term debt	$	766,434	$	626,434	$	646,934	$	471,250	$	271,250
Preferred trust securities	$	—	$	—	$	—	$	125,000	$	125,000
Cash dividends declared per share of common stock (c)	$	0.820	$	0.720	$	0.485	$	0.335	$	0.315

(a) Amounts have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations for all periods presented.

(b) The year ended December 31, 2003, excludes the negative cumulative effect of an accounting change of $3.6 million related to the adoption of SFAS No. 143. The year ended December 31, 2002, excludes the negative cumulative effect of accounting change of $5.5 million related to the adoption of SFAS No. 142 and income from discontinued operations of $9.0 million related to the sale of the Company’s natural gas midstream operations.

(c) Per share amounts have been adjusted for the two-for-one stock split effected on September 1, 2005, for all years presented.

See Item 1A, “Risk Factors,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 4 and 5 to the Consolidated Financial Statements for other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Consolidated Results of Operations

Equitable’s consolidated income from continuing operations before cumulative effect of accounting change for 2005 was $258.6 million, or $2.09 per diluted share, compared with $298.8 million, or $2.37 per diluted share, for 2004, and $165.8 million, or $1.31 per diluted share, for 2003.

The $40.2 million decrease in income from continuing operations before cumulative effect of accounting change from 2004 to 2005 was primarily the result of several non-operational factors. The Company recorded a gain in 2004 as a result of the Westport Resources Corporation (Westport)/Kerr-McGee Corporation (Kerr-McGee) merger in the second quarter of 2004 as well as a gain on the sale of 0.8 million Kerr-McGee shares subsequent to the merger. These gains were partially offset by an expense related to the Company’s charitable contribution of 0.4 million Kerr-McGee shares to the Equitable Resources Foundation, Inc., a community-giving foundation, in 2004. Income from continuing operations before cumulative effect of accounting change in 2005 included a significant gain from the sale of all of the Company’s remaining Kerr-McGee shares, which partially offset the impact of the 2004 items. The net impact on income from continuing operations before income taxes and cumulative effect of accounting change of these four items was a $91.7 million decrease from 2004 to 2005.

Operating income increased $54.1 million from 2004 to 2005 as a result of higher realized selling prices, an increase in sales volumes from production and increased revenues from storage asset optimization opportunities. These increases were offset in some part by increased operating costs resulting primarily from higher natural gas prices and sales volumes, increased incentive expenses and impairment charges related to the Company’s office consolidation.

The Company’s effective tax rate for its continuing operations for the year ended December 31, 2005, was 37.2% compared to 34.2% for both the year ended December 31, 2004, and the year ended December 31, 2003. The increase in the Company’s effective tax rate was primarily the result of tax benefit disallowances under Section 162(m) of the IRC. See Note 6 to the Consolidated Financial Statements.

The 2004 income from continuing operations before cumulative effect of accounting change increased from 2003 primarily due to the gain related to the Westport/Kerr-McGee merger. Higher realized selling prices, an increase in sales volumes from production and the proceeds received from an insurance settlement also helped to improve 2004 earnings. The improved 2004 earnings were partially offset by an increase in incentive expenses, the costs to settle the cash balance portion of a defined benefit pension plan in 2004, decreased gains from the sale of available-for-sale securities in 2004 as compared to 2003, an increase over the prior year in charitable foundation contribution expense, the loss on a 2004 amendment of the Company’s prepaid forward contract and warmer weather in 2004.

Business Segment Results

Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments, minority interest and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters expenses are not allocated to the operating segments. Certain performance-related incentive costs, pension costs and administrative costs totaling $48.0 million, $45.8 million and $20.4 million in 2005, 2004 and 2003, respectively, were not allocated to business segments. The increase in unallocated expenses from 2003 to 2004 was primarily related to increased long-term incentive expenses.

The Company has reconciled each segment’s operating income, equity in earnings of nonconsolidated investments, excluding Westport, minority interest and other income, net to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments, excluding Westport, minority interest and other income, net totals in Note 2 to the Consolidated Financial Statements. Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 2. The Company has also reported the components of each segment’s

operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this information is useful to management and investors in assessing the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations. In addition, management uses these measures for budget planning purposes.

Equitable Utilities

Overview

Equitable Gas continues to work with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. Performance-based incentives provide an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity, or “capacity releases,” for a fee or to participate in the bundling of gas supply and pipeline capacity for “off-system” sales. An “off-system” sale involves the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company. Equitable Gas’ performance-based purchased gas cost credit incentive and a second PA PUC-approved performance-based initiative related to balancing services were available through September 2005. Effective September 30, 2005, an Opinion and Order issued by the PA PUC modified the performance-based purchased gas cost credit design on a prospective basis, providing Equitable Gas with a 25% sharing level of capacity releases and off-system sales, and terminating the Company’s balancing service performance-based incentive. Equitable Gas has filed a petition for reconsideration and clarification with the PA PUC and is awaiting a final Order.

The gas cost rates effective for Equitable Gas’s residential and commercial customers beginning October 1, 2005, include then current high natural gas commodity prices, resulting in residential rates as much as 40% higher than those in place in 2004. These increases can present a significant challenge to the Company’s low-income customers, especially during the winter months. The Company is working with federal and state government officials, industry associations and local foundations to identify sources of funds to assist low income customers in paying their heating bills. In December 2005, Equitable Resources Foundation, Inc. made a grant of $1 million to the local Dollar Energy Fund, a non-profit organization which assists low-income consumers in paying their heating bills. In addition, the Company announced the creation of a new $1 million HELP Grant program, which it manages internally, to provide additional assistance to low-income consumers for the December 2005 through March 2006 winter heating season. Approximately $0.3 million of this amount was credited to eligible customers’ accounts during December 2005. In December 2005, the PA PUC approved Equitable Gas’s petition requesting approval to use up to $7 million of pipeline supplier refunds to benefit low-income customers in its service territory. Under programs designed and managed by Equitable Gas, the funds are being used to assist low-income customers in re-establishing and maintaining their service during the 2005-2006 winter heating season. Additionally, Pennsylvania Governor Rendell proposed and the state legislature approved $19 million in state funding for Low Income Home Energy Assistance Program (“LIHEAP”) grants to be administered by the Pennsylvania Department of Public Welfare. The Company will closely monitor its collections rates and adjust its reserve for uncollectible accounts as necessary.

The Responsible Utility Customer Protection Act, which became effective on December 14, 2004, established new procedures for Pennsylvania utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result, beginning in 2005, the Company was permitted to begin sending winter termination notices to customers whose household income exceeds 250% of the federal poverty level and to complete customer terminations without approval from the PA PUC. In 2005, the Company sent termination notices to a number of eligible customers and will continue to utilize this mechanism in order to reduce delinquent accounts receivable from customers who have the ability to pay.

Results of Operations

	Years Ended December 31,
	2005			2004			%		2003			%

OPERATIONAL DATA

Heating degree days (30 year average = 5,829)	5,543			5,360			3.4		5,695			(5.9	)

Residential sales and transportation volume (MMcf)	24,680			25,520			(3.3	)	27,262			(6.4	)
Commercial and industrial volume (MMcf)	25,368			29,597			(14.3	)	28,784			2.8
Total throughput (MMcf) – Distribution Operations	50,048			55,117			(9.2	)	56,046			(1.7	)

Net operating revenues (thousands):
Distribution Operations (regulated):
Residential	$	102,457		$	104,612		(2.1	)	$	109,821		(4.7	)
Commercial & industrial	46,857			48,563			(3.5	)	50,660			(4.1	)
Other	7,544			5,950			26.8		4,705			26.5
Total Distribution Operations	156,858			159,125			(1.4	)	165,186			(3.7	)
Pipeline Operations (regulated)	53,767			55,123			(2.5	)	52,926			4.2
Energy Marketing	42,739			28,457			50.2		27,011			5.4
Total net operating revenues	$	253,364		$	242,705		4.4		$	245,123		(1.0	)

Total operating expenses as a % of net operating revenues	61.22		%	55.44		%			55.17		%

Operating income (thousands):
Distribution Operations (regulated)	$	40,322		$	56,877		(29.1	)	$	63,093		(9.9	)
Pipeline Operations (regulated)	17,345			24,656			(29.7	)	22,415			10.0
Energy Marketing	40,587			26,616			52.5		24,371			9.2
Total operating income	$	98,254		$	108,149		(9.1	)	$	109,879		(1.6	)

Depreciation, depletion and amortization (DD&A) (thousands):
Distribution Operations	$	19,483		$	17,474		11.5		$	20,025		(12.7	)
Pipeline Operations	8,317			7,985			4.2		7,274			9.8
Energy Marketing	74			170			(56.5	)	284			(40.1	)
Total DD&A	$	27,874		$	25,629		8.8		$	27,583		(7.1	)

Capital expenditures (thousands)	$	61,349		$	56,274		9.0		$	60,414		(6.9	)

	Years Ended December 31,
	2005			2004			%		2003			%

FINANCIAL DATA (thousands)

Distribution revenues (regulated)	$	469,102		$	422,438		11.0		$	396,203		6.6
Pipeline revenues (regulated)	57,534			55,123			4.4		52,926			4.2
Marketing revenues	382,479			300,513			27.3		205,258			46.4
Less: intrasegment revenues	(45,804		)	(46,213		)	(0.9	)	(41,019		)	12.7
Total operating revenues	863,311			731,861			18.0		613,368			19.3

Purchased gas costs	609,947			489,156			24.7		368,245			32.8
Net operating revenues	253,364			242,705			4.4		245,123			(1.0	)

Operating expenses:
Operating and maintenance (O & M)	57,315			52,481			9.2		51,208			2.5
Selling, general and administrative (SG&A)	66,080			56,446			17.1		56,453			—
Impairment charges	3,841			—			100.0		—			—
DD&A	27,874			25,629			8.8		27,583			(7.1	)
Total operating expenses	155,110			134,556			15.3		135,244			(0.5	)
Operating income	$	98,254		$	108,149		(9.1	)	$	109,879		(1.6	)

Fiscal Year Ended December 31, 2005 vs. December 31, 2004

Equitable Utilities’ operating income totaled $98.3 million for 2005 compared to $108.1 million for 2004. Net operating income for 2005 included $16.0 million in charges for the termination and settlement of defined benefit pension plans and a $3.8 million impairment charge in connection with the Company’s office consolidation.

Net operating revenues were $253.4 million for 2005 compared to $242.7 million for 2004. The $10.7 million increase in net operating revenues was primarily due to increased marketing net operating revenues of $14.2 million, resulting primarily from increased storage asset opportunities realized in a high and increasingly volatile natural gas commodity price environment. Distribution Operations’ net operating revenues decreased $2.2 million due to decreased volumes. Distribution Operations’ residential sales and transportation volumes decreased 840 MMcf from 2004 to 2005 due to decreased base load and lower customer use per degree day. These reductions resulted from increased customer conservation, more timely termination of non-paying customers in 2005 and other factors. Increased volumes as a result of colder weather partially offset these decreases in residential volumes, as heating degree days were 5,543 in 2005, which was 3% colder than the 5,360 heating degree days in 2004 although still warmer than normal. Distribution Operations’ commercial and industrial volumes decreased 4,229 MMcf from 2004 to 2005 primarily due to a reduction in industrial throughput to two major steel-making customers. These high volume industrial sales have very low unit margins and did not significantly impact total net operating revenues. Pipeline Operations’ net operating revenues decreased $1.3 million from 2004 to 2005 primarily due to a $3.8 million loss on fuel and retention in excess of the current rates. This loss was partially offset by increased revenues earned in loaning and parking services. These services are contracted on an as-available basis, as opposed to long-term firm storage contracts. This flexibility allows customers, including the Company’s marketing affiliate, to take advantage of the pipeline’s available storage to secure future supply at favorable prices. These services were heavily subscribed in 2005, as higher volatility in natural gas prices provided substantial value for storage options.

Operating expenses totaled $155.1 million for 2005 compared to $134.6 million for 2004. Operating expenses for 2005 included $16.0 million in charges related to the termination and settlement of certain defined benefit pension plans and a $3.8 million loss related to the impairment of certain leased offices, furniture and equipment in connection with the Company’s relocation into its new, consolidated office space. Excluding these

items, operating expenses increased $0.7 million, which resulted from increases of $2.3 million in depreciation expense, $2.2 million in incentive compensation, $1.4 million in customer operations expenses and $1.1 million in employee benefit costs, largely offset by decreases of $4.7 million in bad debt expense and $1.4 million in insurance costs. The increased depreciation expense is a result of increased capital spending in Equitable Utilities over the past two years and is primarily related to computer hardware and software, distribution mainline and service line replacements and the installation of automated meter reading devices. The improvements in bad debt expense are a result of the more timely termination of non-paying customers, a full year impact of a $0.30 per Mcf regulatory surcharge instituted in April 2004, improved efforts to obtain alternative funding for low income customers and other improvements in the collections process. These improvements were offset somewhat in the fourth quarter of 2005 by high commodity rates and cold weather, which resulted in increased provisions for bad debt in that period compared to the prior year.

Fiscal Year Ended December 31, 2004 vs. December 31, 2003

Equitable Utilities’ operating income totaled $108.1 million for 2004 compared to $109.9 million for 2003. The $1.8 million decrease in operating income was primarily due to a decrease in net operating revenues resulting from warmer weather in 2004.

Net operating revenues were $242.7 million for 2004 compared to $245.1 million for 2003. The $2.4 million decrease in net operating revenues was primarily due to warmer weather in the first and fourth quarters of 2004. Heating degree days were 5,360 in 2004, which was 6% warmer than the 5,695 heating degree days in 2003. Additionally in February 2004, a rate moratorium for West Virginia customers expired. As a result, the Distribution Operations subsequently returned to normal gas recovery rates, which led to a decrease in net operating revenues of $0.9 million for the full year 2004. Such decreases for the Distribution Operations were partially offset by increased gathering revenue at the Distribution and Pipeline operations and higher storage related margins at the Pipeline Operations. Distributions Operations’ residential sales and transportation volumes decreased 1,742 MMcf from 2003 to 2004 primarily due to the warmer weather. Distributions Operations’ commercial and industrial volumes increased 813 MMcf from 2003 to 2004 primarily due to increases in sales to steel industry customers, partially offset by reductions in volumes sold to institutional and manufacturing customers and the effects of warmer weather. The increased high-volume steel industry sales have low unit margins and did not significantly impact total net operating revenues.

Operating expenses totaled $134.6 million for 2004 compared to $135.2 million for 2003. This $0.6 million decrease was the result of several factors. DD&A decreased $2.0 million primarily due to a $3.5 million adjustment related to increases in the estimated useful life for Equitable Gas’ main lines and services lines resulting from a PA PUC mandated asset service life study. This decrease was partially offset by increases in DD&A related mainly to increased capital in 2004, of which approximately $0.5 million was related to the implementation of a customer information system. SG&A was relatively consistent between years, with several offsetting fluctuations. Bad debt expense decreased by $1.7 million from 2003 to 2004 due to a reduction of a regulatory asset reserve of $7.5 million in 2004, partially offset by an increase of $5.8 million mainly related to delays in initiating collection activity due to the implementation of a customer information system in 2004 as well as increased gas rates in that year. The reduction in the regulatory asset reserve was due to Equitable Gas having higher than anticipated recoveries for the Delinquency Reduction Opportunity Program through payment and rates. Offsetting this and other reductions in SG&A, the Distribution Operations experienced increased insurance and legal costs of $1.7 million, a $0.9 million increase in Pennsylvania franchise tax, $0.7 million of expense incurred primarily related to increased overtime and contractor costs as a result of the flooding which occurred in September 2004 due to Hurricane Ivan and other slight increases in administrative expense accruals. O & M costs increased primarily as a result of $1.1 million related to the implementation of the customer information system.

See “Capital Resources and Liquidity” section for discussion of Equitable Utilities’ capital expenditures during 2005, 2004 and 2003.

Outlook

Equitable Utilities’ business strategy is focused on effectively managing its gas distribution assets, optimizing its return on assets, selectively growing its gas distribution business through acquisition and developing a portfolio

of closely related, unregulated businesses with an emphasis on risk management and earnings viability. Key elements of Equitable Utilities’ strategy include:

• Enhancing the value and growth potential of the regulated utility operations. Equitable Utilities will seek to enhance the value and growth of its existing utility assets by managing its capital spending effectively; establishing a reputation for excellent customer service; continuing to leverage technology; working to achieve authorized returns in each jurisdiction and, in those jurisdictions where it has performance-based rates, sharing the benefits with its customers; and maintaining earnings and rate stability through regulatory arrangements that fairly balance the interests of customers and shareholders.

• Selectively evaluating acquisitions. The Company will selectively examine and evaluate the acquisition of natural gas distribution, gas pipeline or other gas-related assets. The Company’s acquisition criteria include the ability to generate operational synergies, strategic fit relative to the Company’s core competencies, value from near-term earnings contributions and adequate returns on invested capital.

• Selectively expanding Equitable Utilities natural gas storage and gathering operations. The Company intends to continue to expand its natural gas storage and gathering businesses to provide disciplined incremental earnings growth for shareholders. In its asset management business, Equitable Utilities intends to grow its business by providing its customers with gas supply, storage and asset management options; capturing value from increased natural gas gathering margins; providing producers with access to markets for their increased production; and arbitraging pipeline and storage assets across various gas markets and time horizons. In its underground storage business, Equitable Utilities will continue to invest capital to expand its operational capabilities by increasing storage deliverability, thereby providing an opportunity to capture increased value from the volatility in natural gas prices. Capturing this value from Equitable Utilities’ storage assets may increase the volatility of reported earnings from this business. Equitable Utilities will continue to focus on marketing energy to customers from its own assets; controlling costs; and managing its portfolio with smart business decisions while looking for additional opportunities to provide economical storage services in the regions in which the Company’s utilities operate.

Equitable Supply

Overview

Sale of Gas Properties

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $142 million after purchase price adjustments. The unit of production depletion rate (or DD&A rate) decreased by $0.04 per Mcfe prospectively as a result of this transaction. In accordance with SFAS No. 19, this sale of only a portion of the gas properties was treated as a normal retirement with no gain or loss recognized, as doing so did not significantly affect the DD&A rate.

Purchase of Interest in Eastern Seven Partners, L.P. (ESP)

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. Production related to this interest during 2005 totaled approximately 8.2 Bcf. The DD&A rate increased by $0.04 per Mcfe prospectively as a result of this transaction.

Results of Operations

	Years Ended December 31,
	2005			2004			%		2003		%

OPERATIONAL DATA

Capital expenditures (thousands) (a)	$	264,095		$	141,661		86.4		$	204,527	(30.7	)

Production:
Total sales volumes (MMcfe)	73,909			67,731			9.1		64,306		5.3
Average (well-head) sales price ($/Mcfe)	$	5.17		$	4.46		15.9		$	3.91	14.1

Company usage, line loss (MMcfe)	4,897			5,090			(3.8	)	5,501		(7.5	)

Natural gas inventory usage, net (MMcfe)	(51		)	(61		)	(16.4	)	112		(154.5	)

Natural gas and oil production (MMcfe) (b)	78,755			72,760			8.2		69,919		4.1

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.29		$	0.26		11.5		$	0.23	13.0
Production taxes ($/Mcfe)	$	0.49		$	0.34		44.1		$	0.28	21.4
Production depletion ($/Mcfe)	$	0.59		$	0.54		9.3		$	0.49	10.2

Gathering:
Gathered volumes (MMcfe)	121,044			127,339			(4.9	)	126,674		0.5
Average gathering fee ($/Mcfe)	$	0.82		$	0.58		41.4		$	0.55	5.5
Gathering and compression expense ($/Mcfe)	$	0.31		$	0.28		10.7		$	0.20	40.0
Gathering and compression depreciation ($/Mcfe)	$	0.12		$	0.11		9.1		$	0.09	22.2
(in thousands)
Production operating income	$	260,931		$	212,657		22.7		$	172,384	23.4
Gathering operating income	32,650			14,712			121.9		23,411		(37.2	)
Total operating income	$	293,581		$	227,369		29.1		$	195,795	16.1

Production depletion	$	46,750		$	39,100		19.6		$	33,911	15.3
Gathering and compression depreciation	14,312			13,441			6.5		11,711		14.8
Other DD&A	3,835			3,295			16.4		3,126		5.4
Total DD&A	$	64,897		$	55,836		16.2		$	48,748	14.5

	Years Ended December 31,
	2005		2004		%		2003			%

FINANCIAL DATA (thousands)

Production revenues	$	390,290	$	315,986	23.5		$	262,607		20.3
Gathering revenues (c)	98,901		74,442		32.9		69,827			6.6
Total operating revenues	489,191		390,428		25.3		332,434			17.4

Operating expenses:
LOE, excluding production taxes	23,195		18,685		24.1		15,867			17.8
Production taxes (d)	38,288		24,589		55.7		19,820			24.1
Gathering and compression (O&M)	38,101		35,494		7.3		25,110			41.4
SG&A	30,610		28,455		7.6		27,094			5.0
Impairment charges	519		—		100.0		—			—
DD&A	64,897		55,836		16.2		48,748			14.5
Total operating expenses	195,610		163,059		20.0		136,639			19.3
Operating income	$	293,581	$	227,369	29.1		$	195,795		16.1

Equity in earnings of nonconsolidated investments	$	493	$	688	(28.3	)	$	431		59.6
Other income, net	$	—	$	576	(100.0	)	$	—		100.0
Minority interest	$	—	$	—	—		$	(871	)	(100.0	)

(a) 2005 capital expenditures include $57.5 million for the acquisition of the limited partnership interest in ESP. 2003 capital expenditures include $44.2 million for the purchase of the remaining 31% limited partnership interest in Appalachian Basin Partners, L.P. (ABP).

(b) Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory usage, net.

(c) Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field to the trunk or main transmission line. Many contracts are for a blended gas commodity and gathering price, in which case the Company utilizes standard measures in order to split the price into its two components.

(d) Production taxes include severance and production-related ad valorem and other property taxes.

Fiscal Year Ended December 31, 2005 vs. December 31, 2004

Equitable Supply’s operating income totaled $293.6 million for 2005 compared to $227.4 million for 2004, an increase of $66.2 million between years. Production operating income increased $48.2 million primarily due to an increase in well-head sales price and an increase in sales volumes, partially offset by increased production operating expenses. Gathering operating income increased $18.0 million due to an increase in the average gathering fee, partially offset by decreased gathered volumes and increased gathering operating expenses.

Total operating revenues were $489.2 million for 2005 compared to $390.4 million for 2004. The $98.8 million increase in net operating revenues was primarily due to a 16% increase in the average well-head sales price, a 9% increase in production total sales volumes and a 33% increase in gathering revenues. The $0.71 per Mcfe increase in the average well-head sales price was mainly attributable to increased market prices on unhedged volumes partially offset by an adjustment of $10.6 million. The adjustment was principally due to the Company’s conclusion that the well-head sales price allocated to a third party’s working interest gas in previous periods may have been lower than the Company was obligated to pay. The 9% increase in production total sales volumes was

primarily the result of the purchase of ESP, partially offset by the sale of certain non-core gas properties. The 33% increase in revenues from gathering fees was attributable to a 41% increase in the average gathering fee, partially offset by a 5% decline in gathered volumes. The increase in average gathering fee is reflective of the Company’s commitment to an increased infrastructure capital program, along with higher gas prices and related operating cost increases. The decrease in gathered volumes in 2005 was primarily due to the sale of certain non-core gathering assets and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for Company production in 2005. These increases in production and gathering revenues were partially offset by the recognition of a gain of $2.7 million in 2004 that resulted from the renegotiation of a processing agreement.

Operating expenses totaled $195.6 million for 2005 compared to $163.1 million for 2004. A significant reason for this $32.5 million increase was due to additional costs of $15.0 million resulting from the purchase of ESP. The $15.0 million of costs were primarily related to DD&A ($4.7 million), production taxes ($4.6 million), lease operating expenses ($3.7 million) and gathering expenses ($2.0 million). Excluding the ESP costs, the $17.5 million increase in operating expenses was due to increases of $9.1 million in production taxes, $4.4 million in DD&A, $2.1 million in SG&A, $0.8 million in LOE, $0.6 million in gathering expenses and $0.5 million in impairment charges. The increase in production taxes was due to increased property taxes ($5.4 million) and severance taxes ($3.7 million). The increase in property taxes was a direct result of increased prices and sales volumes in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and sales volumes. The increase in severance taxes (a production tax directly imposed on the value of gas extracted) was primarily due to higher gas commodity prices and sales volumes in the various taxing jurisdictions that impose such taxes.

The increase in DD&A excluding ESP was due to a $0.05 per Mcf increase in the unit depletion rate ($4.3 million) and increased depreciation on a higher asset base ($1.4 million), partially offset by lower depletion as a result of decreased volumes from the sale of certain non-core gas properties ($1.3 million). The increase in the unit depletion rate was primarily due to the net development capital additions in 2005 and 2004 on a relatively consistent proved reserve base. The increase in SG&A was the result of increased legal and professional fees and bad debt expenses. The increase in LOE was the result of the Company’s strategy to focus on current infrastructure as well as increased costs from vendors due to higher gas prices. The increase in gathering expenses was primarily attributable to increased electricity charges resulting from newly installed electric compressors, field labor and related employment costs and compressor station operation and repair costs. The gathering and compression increases are consistent with the Company’s strategic decision to focus on improving gathering and compression and metering effectiveness. Such increases were partially offset by reductions in gathering expenses due to reduced gathered volumes. The impairment charges in 2005 were related to the Company’s relocation of its corporate headquarters and other operations to its new consolidated office space.

Other income, net for 2004 was the result of a $6.1 million settlement received from a previously disputed insurance coverage claim, offset by a $5.5 million expense related to the Company’s settlement of a prepaid forward contract in 2004.

Fiscal Year Ended December 31, 2004 vs. December 31, 2003

Equitable Supply’s operating income totaled $227.4 million for 2004 compared to $195.8 million for 2003. Total operating revenues were $390.4 million for 2004 compared to $332.4 million for 2003. The $58.0 million increase in total operating revenues was primarily due to a 14% increase in the average well-head sales price, a 5% increase in production total sales volumes and a 7% increase in gathering revenues. The $0.55 per Mcfe increase in the average well-head sales price was attributable to higher gas commodity prices, increased volumes at higher hedged prices and increased basis over the same period in 2003. The 5% increase in production total sales volumes was primarily the result of new wells drilled and production enhancements partially offset by the normal production decline in the Company’s wells. The increase in gathering revenues was attributable to a 6% increase in the average gathering fee and higher Equitable Production sales volumes (resulting in increased gathered volumes), partially offset by third party customer volume shut-ins.

Operating expenses were $163.1 million for 2004 compared to $136.6 million for 2003. This $26.5 million increase was due to increases of $10.4 million in gathering and compression expenses, $7.1 million in DD&A, $4.8

million in production taxes, $2.8 million in LOE, and $1.4 million in SG&A. The increase in gathering and compression expenses was primarily attributable to an increase in compressor station operation and repair costs, field labor and related employment costs, field line maintenance costs and compressor electricity charges resulting from newly installed electric compressors. The additional compression costs resulted from a 24% increase in horse power to approximately 112,000 horse power in 2004 from approximately 90,000 horse power in 2003. The increase in field labor was due to an increase in headcount related to Equitable Gathering’s strategy to spend more time and resources to aggressively tend to the improvement of the base infrastructure. Actions taken by Equitable Gathering to support this strategy, such as the installation of compressor stations and facilities to reduce surface pressure and efforts related to reducing the internal curtailment of gas sales, increased compression and field line maintenance costs in 2004.

The increase in DD&A was primarily due to a $0.05 per Mcfe increase in the unit depletion rate, increased production volumes and capital expenditures for gathering system improvements and extensions. The $0.05 per Mcfe increase in the unit depletion rate was due to the net development capital additions in 2003 on a relatively consistent proved reserve base. The increase in production taxes was primarily due to higher gas commodity prices and sales volumes. The increase in LOE was primarily due to a charge to earnings for environmental site assessments performed in accordance with the Company’s amended Spill Prevention, Control and Countermeasure (SPCC) compliance plan and increased liability insurance premiums. The increase in SG&A was due to increased franchise taxes in 2004.

See “Capital Resources and Liquidity” section for discussion of Equitable Supply’s capital expenditures during 2005, 2004 and 2003.

Outlook

Equitable Supply’s business strategy is focused on achieving profit maximization by primarily focusing on developing new opportunities, through increased drilling and other development in the Appalachian Basin, as well as improvements to and expansion of its gathering systems, and secondarily focusing on cost control. The Company believes that the margin leverage from realizable gas prices outweighs the increase in unit cost structure necessary to implement this strategy. Key elements of Equitable Supply’s strategy include:

• Expanding production through the drilling program. Equitable Supply has a multi-year drilling program which will enable the Company to continue the growth of its production business. Equitable Supply intends to increase its drilling rate by over 20% to 550 wells in 2006. The Company’s forecasted capital expenditures for 2006 include a 48% increase in expenditures related to Appalachian development. The Company believes that it has available on acreage it controls at least 4,600 net drilling locations on unproved properties, in addition to 2,292 net proved undeveloped drilling locations. Equitable Supply believes that its 692 Bcfe of proved undeveloped reserves will be developed within a reasonable time period (currently estimated to be five years) because (1) Equitable Supply has completed substantially all of the wells it has drilled in the last three years, (2) Equitable Supply developed proved undeveloped reserves of 70 Bcfe and 62 Bcfe during 2005 and 2004, respectively, and (3) Equitable Supply’s plans include developing similar levels of proved undeveloped reserves going forward.

• Maintaining and enhancing base well production. Equitable Supply will seek to maximize production of existing base wells by increased focus on maintenance, technology improvements and recompletions (deepening a well to another horizon or attempting to secure production from a shallower horizon). Through these activities, Equitable Supply can benefit from higher gas prices by obtaining accelerated volumes from its existing wells.

• Expanding the gathering system to support drilling and third party gathering revenues. The Company will continue to expand its pipeline and compression infrastructure in order to manage increased gathered volumes from both Company drilling programs and third party shippers. The Company plans to expand its gathering systems by approximately 190 miles of pipeline and approximately 20,000 horsepower of compression in 2006. Many of the existing pipelines will be increased in size to handle these additional volumes and new pipelines will be constructed to expanded drilling areas. The Company plans to build new compression stations as well as expand existing stations in order to transport these volumes to sales points on major interstate pipelines.

• Investing in midstream gathering and processing in the Appalachian Basin. In a high price natural gas market, infrastructure needed to support increased drilling and to move gas from wellhead to market presents an acute need but also a significant opportunity for the Company. The Company has begun a significant new pipeline infrastructure project, the Big Sandy Pipeline. The 60 mile, 20-inch pipeline is expected to have a capacity of 70,000 dekatherms per day and will connect the Kentucky Hydrocarbon processing plant in Langley, Kentucky with the Tennessee Gas Pipeline interconnect in Carter County, Kentucky. The Big Sandy Pipeline is projected to cost a total of $83 million. The Company is also planning an upgrade to its Langley plant. These projects are scheduled for operation in 2007 and will enable the Company to further support its drilling growth, mitigate pipeline curtailments, increase flexibility and reliability of its midstream gathering systems and capitalize on third party producer demand in the Appalachian Basin. Natural gas processing expansion will continue to be required in order to meet the interstate pipeline gas quality standards and will represent an opportunity for the Company. The Company is looking at several processing, pipeline and compression expansion opportunities in Appalachia and expects to invest in additional projects in 2006 and beyond.

• Optimizing throughput of the existing gathering system. The Company will optimize its existing gathering assets by making technological improvements, upgrading existing compressors and eliminating bottlenecks in its gathering systems. While these initiatives will result in increased costs, the Company will continue to focus on ensuring that costs incurred in its gathering activities, both operating and capital, plus a reasonable rate of return on its gathering assets, are recovered in rates for transporting gas on its gathering systems. A part of this strategy includes increasing the rates that the Company charges to parties who transport gas on these systems. In certain instances, such rate increases require regulatory action. The Company expects the process of increasing gathering rates to extend beyond 2006.

Other Income Statement Items

	Years Ended December 31,
	2005		2004			2003
	(Thousands)
Income (loss) from discontinued operations	$	1,481	$	(18,936	)	$	7,807
Gain on sale of available-for-sale securities, net	110,280		3,024			13,985
Other income, net	1,195		3,692			—
Gain on exchange of Westport for Kerr-McGee shares	—		217,212			—
Charitable foundation contribution	—		(18,226		)	(9,279		)
Equity earnings of Westport	—		—			3,614

As noted in Item 1, the Company’s NORESCO business is classified as discontinued operations due to the sale of the NORESCO domestic business and pending sale of the Company’s remaining international investment. Income (loss) from discontinued operations for 2004 included approximately $23.9 million of after-tax impairments on international investments and charges for related reserves, while income (loss) from discontinued operations for 2005 included the reversal of approximately $7.8 million of these reserves (after tax) due to improved business conditions in the related international markets, as well as a $6.4 million tax benefit from the reorganization of the Company’s international assets in 2005. These increases in 2005 as compared to 2004 were partially offset by $18.7 million in after-tax charges recorded in 2005, related to the recording of $13.7 million of income taxes on the sale and other costs incurred as a result of the sale transaction.

During 2005, the Company sold its remaining 7.0 million Kerr-McGee shares resulting in pre-tax gains net of collar termination costs totaling $110.3 million. During 2004, the Company sold 0.8 million Kerr-McGee shares, resulting in a pre-tax gain of $3.0 million. During 2003, the Company sold approximately 1.5 million Westport shares, resulting in a pre-tax gain of $14.0 million.

Other income, net includes pre-tax dividend income relating to the Kerr-McGee shares held by the Company of $1.2 million and $3.1 million for 2005 and 2004, respectively.

As a result of the 2004 merger between Westport and Kerr-McGee, the Company recognized a gain of $217.2 million on the exchange of its Westport shares for Kerr-McGee shares. See Note 9 to the Company’s Consolidated Financial Statements for further information on this transaction.

In the first quarter of 2003, the Company established Equitable Resources Foundation, Inc. to facilitate the Company’s charitable giving program. This foundation received additional funding in the second quarter of 2004. See Note 9 to the Company’s Consolidated Financial Statements for information regarding the charitable foundation contribution expense recorded upon contributions of Kerr-McGee shares made to Equitable Resources Foundation, Inc. during 2004.

The Company reported $3.6 million in equity earnings from its minority ownership in Westport during the first quarter 2003. At the end of the first quarter of 2003, the Company’s ownership position in Westport decreased below 20%. As a result of the decreased ownership, the Company changed the accounting treatment for its investment from the equity method to the available-for-sale method effective March 31, 2003.

Interest Expense

	Years Ended December 31,
	2005		2004		2003
	(Thousands)

Interest expense	$	44,437	$	42,520	$	41,530

Interest expense increased by $1.9 million from 2004 to 2005 primarily due to the issuance of $150 million of notes with a stated interest rate of 5% on September 30, 2005 and an increase in the average annual short-term debt interest rate. These increases were partially offset by the maturity of $10 million of medium-term notes during 2005.

Interest expense increased by $1.0 million from 2003 to 2004 primarily due to increases in short-term borrowing activity during 2004 as well as an increase in the average annual short-term debt interest rate.

Average annual interest rates on the Company’s short-term debt were 3.5%, 1.7% and 1.2% for 2005, 2004 and 2003, respectively.

Capital Resources and Liquidity

Operating Activities

Cash flows used in operating activities totaled $312.0 million for 2005 as compared to $180.0 million of cash flows provided by operating activities for 2004, a net increase of $492.0 in cash flows used in operating activities between years. The increase in cash flows used in operating activities was attributable to the following:

• an increase in margin deposit requirements on the Company’s natural gas hedge agreements to $317.8 million as of December 31, 2005, from $36.9 million as of December 31, 2004. As further detailed under the captions “Financing Activities” and “Short-term Borrowings” to follow, the Company has taken steps to ensure it has adequate liquidity for working capital and margin requirement needs;

• an increase in tax payments to $251.5 million in 2005 compared to $23.0 million in 2004, primarily due to the sale of the Company’s Kerr-McGee shares, the sale of the NORESCO discontinued operations and the sale of non-core gas properties for significant taxable gains in 2005;

• an increase in inventory to $289.9 million as of December 31, 2005, from $204.6 million as of December 31, 2004, primarily due to increased natural gas prices on volumes stored in 2005 compared to 2004;

• cash contributions of approximately $20.4 million to its pension plan during 2005 as compared to no contributions in 2004.

partially offset by:

• an increase in accounts payable to $242.6 million as of December 31, 2005, from $171.2 million as of December 31, 2004, largely due to increased operating costs resulting from increased drilling activity and higher natural gas prices.

Cash flows provided by operating activities totaled $180.0 million for 2004 as compared to $128.6 million for 2003, a $51.4 million increase between years. The increase in cash flows provided by operating activities was attributable to the following:

• increased collections from customers in 2004 as compared to 2003, driven primarily by increased net operating revenues in the Company’s Supply segment;

• no cash contributions to the Company’s pension plan in 2004, as compared to a cash contribution of $51.8 million in 2003;

partially offset by:

• a $36.8 million payment in 2004 resulting from the Company’s amendment of a prepaid forward contract in the second quarter of 2004. This amendment resulted in the Company repaying the net present value of the portion of the prepayment related to undelivered quantities of natural gas in the original contract;

• Cash flows from operations were also affected by other working capital changes during 2004.

Investing Activities

Cash flows provided by investing activities totaled $347.7 million for 2005 as compared to $158.5 million of cash flows used in investing activities for 2004, a net increase of $506.2 million in cash flows provided by investing activities between years. The increase in cash flows provided by investing activities was attributable to the following:

• proceeds of $460.5 million from the sale of the Company’s remaining 7.0 million shares of Kerr-McGee in 2005, as compared to proceeds of $42.9 million from the sale of 0.8 million shares of Kerr-McGee in 2004;

• proceeds of $142.0 million from the sale of certain non-core gas properties and associated gathering assets in 2005;

• proceeds of $80.0 million from the sale of the domestic operations of the Company’s NORESCO business segment in 2005;

partially offset by:

• an increase in capital expenditures to $333 million in 2005 from $202 million in 2004. See discussion of capital expenditures below.

Cash flows used in investing activities totaled $158.5 million for 2004 as compared to $215.3 million for 2003, a net decrease of $56.8 in cash flows used in investing activities between years. The decrease in cash flows used in investing activities was primarily attributable to a decrease in capital expenditures (see discussion of capital expenditures below) to $202 million in 2004 from $265 million in 2003.

Capital Expenditures

2006 Forecast

2005 Actual

2004 Actual

2003 Actual

Development of Appalachian holdings
(primarily drilling)

194 million

131 million

92 million

126 million

plus $58 million for the purchase of ESP

plus $44 million for the purchase of 31% of ABP

Gathering system improvements and extensions

222 million

75 million

50 million

34 million

Equitable Utilities

78 million

61 million

56 million

60 million

Headquarters

3 million

8 million

4 million

1 million

Total

497 million

333 million

202 million

265 million

* The 2006 capital expenditures include 2005 capital commitments totaling $105 million.

Capital expenditures for Appalachian holdings development and gathering system improvements and extensions increased in 2005 as compared to 2004 primarily due to an increased drilling and development plan in 2005. Such expenditures were lower in 2004 as compared to 2003 primarily due to a decrease in the level of development drilling in the Appalachian holdings to allow Equitable Supply to concentrate on its core assets and ensure a proper level of return on all new projects.

Capital expenditures for Equitable Utilities increased in 2005 as compared to 2004 due to the installation of electronic meter reading technology on approximately 113,000 of the 265,000 meters in the Distribution Operations. The $17 million project to install electronic meter reading technology on all 265,000 meters is expected to be completed in 2006. The Company anticipates that the benefits from this project will result in approximately $2.0 million in annual cost savings. Capital expenditures for Equitable Utilities decreased in 2004 as compared to 2003 due to a decrease in technological enhancement project spending, partially offset by increased main line replacement costs and new business development spending.

The Company’s capital expenditures forecasted for 2006 represent a significant increase over capital expenditures in 2005. The $194 million targeted for the development of Appalachian holdings in 2006 represents a $63 million increase over 2005 which is attributable to an expanded drilling program in Virginia, West Virginia and Kentucky. The $222 million forecasted for 2006 gathering system improvements and extensions includes a further expansion in infrastructure to support the Company’s current and future drilling plans and expenditures for the Big Sandy Pipeline project. The pipeline, which is projected to cost a total of $83 million, including $53 million in the 2006 forecast, is scheduled for operation in 2007.

The $78 million forecasted for Equitable Utilities includes $73 million for infrastructure improvements and $5 million for new business development. The infrastructure improvements include improvements to existing distribution and transmission lines, the continued installation of automated metering devices in the Distribution business and storage enhancements. The new business capital is planned for extensions of existing infrastructure into adjacent geographic areas.

The Company expects to finance its capital expenditures with cash generated from operations and with short-term debt. See discussion in the “Short-term Borrowings” section below regarding the financing capacity of the Company.

Financing Activities

Cash flows provided by financing activities totaled $39.2 million for 2005 as compared to $55.8 million of cash flows used in financing activities for 2004, a net increase of $95.0 in cash flows provided by financing activities between years. The increase in cash flows provided by financing activities from 2004 to 2005 was attributable largely to the following:

• proceeds from the issuance in 2005 of $150 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015;

• a decrease in current maturities of the Company’s medium-term notes of $10.5 million in 2005;

partially offset by:

• less of an increase in amounts borrowed under short-term loans in 2005 as compared to 2004;

• an increase in dividends paid to shareholders to $99.7 million in 2005 from $89.4 million in 2004;

• an increase in the cost to repurchase shares of the Company’s outstanding common stock to $122.3 million for 3.6 million shares for 2005 from $118.5 million for 4.7 million shares for 2004.

Cash flows used in financing activities totaled $55.8 million for 2004 as compared to $112.9 million of cash flows provided by financing activities for 2003, a net increase of $168.7 million in cash flows used in financing activities between years. The increase in cash flows used by financing activities from 2003 to 2004 was attributable to the following:

• a net increase of $75.0 million in long-term debt during 2003 due to the issuance of $200 million of notes offset by the redemption of $125 million of Trust Preferred Securities, with no such items in 2004;

• an increase in the cost to repurchase shares of the Company’s outstanding common stock to $118.5 million for 4.7 million shares in 2004 from $55.2 million for 2.9 million shares in 2003;

• an increase in dividends paid to shareholders to $89.4 million in 2004 from $60.4 million in 2003;

The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are more than adequate to meet the Company’s reasonably foreseeable liquidity requirements.

Short-term Borrowings

Cash required for operations is affected primarily by the seasonal nature of the Company’s natural gas distribution operations and the volatility of oil and natural gas commodity prices. The Company’s $1 billion, five-year revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other lawful purposes including support of the Company’s commercial paper program. Historically, short-term borrowings under the commercial paper program have been used mainly to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season. Due to continued higher than average natural gas prices and resulting increases in the Company’s net liability position under its natural gas swap agreements, the Company also borrowed increased amounts through its commercial paper program to fund its interest-bearing margin deposits under its exchange-traded natural gas agreements. The amount of commercial paper outstanding at December 31, 2005 was $365.3 million. Interest rates on these short-term loans averaged 3.5% during 2005.

Security Ratings and Financing Triggers

The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

Rating Service	Unsecured Medium-Term Notes	Commercial Paper
Moody’s Investors Service	A-2	P-1
Standard & Poor’s Ratings Services	A -	A-2

The Company’s credit ratings on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s credit rating, the higher the level of fees and borrowing rate. As of December 31, 2005, the Company had no outstanding borrowings against these lines of credit. The Company pays facility fees to maintain credit availability.

The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, it may significantly limit the Company’s access to the commercial paper market and borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings, incur increased margin deposit requirements, and the potential pool of investors and funding sources would decrease.

The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. This calculation excludes unrealized gains or losses from hedging transactions recorded in accumulated other comprehensive income (loss). As of December 31, 2005, the Company is in compliance with all existing debt provisions and covenants.

Commodity Risk Management

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The preponderance of derivative commodity instruments currently utilized by the Company are fixed price swaps or NYMEX-traded forwards.

During the third quarter of 2005, the Company increased its hedge position for 2006 through 2012. The new hedges are collars, which protect revenues from decreases in natural gas prices below a floor but also limit the upside exposure to increases in prices to a cap.

The approximate volumes and prices of the Company’s hedges for 2006 through 2008 are:

	2006		2007		2008
Swaps
Total Volume (Bcf)	59		56		54
Average Price per Mcf (NYMEX)*	$	4.77	$	4.74	$	4.64

Collars
Total Volume (Bcf)	7		7		7
Average Floor Price per Mcf (NYMEX)*	$	7.35	$	7.35	$	7.35
Average Cap Price per Mcf (NYMEX)*	$	10.84	$	10.84	$	10.84

* The above price is based on a conversion rate of 1.05 MMBtu/Mcf

The Company’s current hedged position provides price protection for a substantial portion of expected equity production for the years 2006 through 2008 and a significant portion of expected equity production for the years 2009 through 2012. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is less than $0.01 per diluted share for 2006 and ranges from $0.01 to $0.02 per diluted share per year for 2007 and 2008. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices. See Note 3 to the Company’s Consolidated Financial Statements for further discussion.

Investment Securities

The Company’s available-for-sale investments as of December 31, 2005 consist of approximately $25.2 million of equity securities that are intended to fund certain liabilities for which the Company is self-insured. These investments are recorded at fair market value. During 2005, the Company sold all of its remaining 7.0 million shares of Kerr-McGee in various transactions for total net pre-tax proceeds of $460.5 million and a total pre-tax gain of $110.3 million, net of $95.8 million in costs associated with the termination of the three related variable share forward transactions entered into in June 2004 subsequent to the Westport/Kerr-McGee merger. The sale of these shares was determined by the Company to constitute the best use of this asset due to the significant appreciation in the value of the Kerr-McGee shares during 2005.

Other Items

Off-Balance Sheet Arrangements

The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of December 31, 2005, ANPI had $243 million of total assets and $498 million of total liabilities (including $155 million of long-term debt, including current maturities), excluding minority interest.

The Company provides a liquidity reserve guarantee to ANPI, which is subject to certain restrictions and limitations, and is secured by the fair market value of the assets purchased by the Appalachian Natural Gas Trust (ANGT). The Company received a market-based fee for the issuance of the reserve guarantee. As of December 31, 2005, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $43 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance.

The Company has entered into an agreement with ANGT to provide gathering and operating services to deliver ANGT’s gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The revenue earned from these fees totaled approximately $15.5 million for 2005.

In connection with the sale of its NORESCO domestic business, the Company through indirect subsidiaries has agreed to maintain certain guarantees which benefit NORESCO. These guarantees, the majority of which predate the sale of NORESCO, became off-balance sheet arrangements upon the closing of the sale of NORESCO on December 30, 2005. These arrangements include guarantees of NORESCO’s obligations to the purchasers of certain of NORESCO’s contract receivables and agreements to maintain guarantees supporting NORESCO’s obligations under certain customer contracts. In addition, NORESCO and the purchaser agreed that NORESCO would fully perform its obligations under each underlying agreement and that the purchaser or NORESCO would reimburse the Company for losses under the guarantees. The purchaser’s obligations to reimburse the Company are capped at $6 million. The Company has performed an extensive review of these guarantees and of the underlying obligations and has determined that the likelihood the Company will be required to perform on these arrangements is remote. As such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees. The total maximum potential obligation under these arrangements is estimated to be approximately $512 million and will decrease over time as the guarantees expire or the underlying obligations are fulfilled by NORESCO.

See Note 20 to the Consolidated Financial Statements for further discussion of the Company’s guarantees.

Pension Plans

Total pension expense recognized by the Company in 2005, 2004 and 2003, excluding special termination benefits, settlement losses and curtailment losses, totaled $0.4 million, $0.4 million and $2.9 million, respectively. The Company recognized special termination benefits, settlement losses and curtailment losses in 2005, 2004 and 2003 of $18.4 million, $16.2 million and $4.4 million, respectively. As a result of these one-time costs, the Company’s projected benefit obligation decreased by approximately $34.6 million.

During 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, the Company recognized a settlement expense of $12.1 million during 2005. During the fourth quarter of 2005, the Company settled its pension obligation with certain non-represented employees. As a result of this settlement, the Company recognized a settlement expense of approximately $2.4 million in 2005.

The Company made cash contributions of approximately $20.4 million to its pension plan during 2005 as a result of the previously described settlements. The Company expects to make a cash contribution of approximately $2.3 million to its pension plan during 2006. The Company was not required to, and consequently did not make any contribution to its pension plans during the year ended December 31, 2004. The Company made cash contributions totaling $51.8 million to its pension plan during the year ended December 31, 2003, primarily due to the Company’s benefit obligation being significantly under funded.

Incentive Compensation

The Company has now fully transitioned to a long-term incentive approach that is focused on performance-restricted stock or units and time-restricted stock. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns management’s incentives with shareholder rewards than is the case with traditional stock options. The Company has long utilized time-restricted stock in its compensation plans and began issuing performance-restricted units in 2002. No new stock options have been awarded since 2003.

The Company recorded the following incentive compensation expense in continuing operations for the periods indicated below:

	Year Ended December 31,
	2005		2004		2003
	(millions)
Short-term incentive compensation expense	$	12.9	$	13.7	$	9.5
Long-term incentive compensation expense	46.4		28.3		16.6
Total incentive compensation expense	$	59.3	$	42.0	$	26.1

The long-term incentive compensation expenses are primarily associated with Executive Performance Incentive Programs (“the Programs”). The long-term incentive compensation expenses during 2005 were higher than during 2004 primarily due to a higher estimated share price for the Programs being expensed, as a result of the Company’s share price appreciation, and a greater number of units granted under the current Programs as compared to the Programs in place during 2004. The long-term incentive compensation expenses during 2004 were higher than during 2003 primarily as a result of the Company’s share price appreciation as well.

The Company currently estimates 2006 total incentive compensation expense of approximately $35 million, less than that incurred during 2005 due primarily to the payout of one of the Programs in December 2005.

Federal Legislation

The American Jobs Creation Act of 2004 (the Jobs Act), which the President signed into law on October 22, 2004, was the first major corporate tax act in a number of years. Some of the key provisions of the Jobs Act include a new domestic manufacturing deduction, oil and gas producer incentives (not an extension of the nonconventional fuels tax credit), new tax shelter penalties, restrictions on deferred compensation and numerous other issue-specific provisions aimed at specific transactions. On September 29, 2005, the Treasury Department and the IRS issued proposed regulations providing deferred compensation guidance under the new legislation. During 2005, the Company completed its review of the legislation’s impact on its executive compensation plans and the Compensation Committee of the Company’s Board of Directors decided to end the Company’s deferred compensation programs for employees. As a result, the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily as the result of impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.

Rate Regulation

The Company’s Distribution Operations and Pipeline Operations are subject to various forms of regulation as previously discussed. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71. As described in Notes 1 and 10 to the Consolidated Financial Statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.

Schedule of Contractual Obligations

The following table details the future projected payments associated with the Company’s contractual obligations as of December 31, 2005.

	Total		2006		2007-2008		2009-2010		2011+
	(Thousands)
Long-term debt	$	766,434	$	3,000	$	10,000	$	4,300	$	749,134
Interest expense	543,241		45,178		88,980		88,567		320,516
Purchase obligations	187,154		32,393		56,104		48,927		49,730
Operating leases	62,848		7,337		12,326		7,910		35,275
Other long-term liabilities	89,860		—		89,860		—		—
Total contractual obligations	$	1,649,537	$	87,908	$	257,270	$	149,704	$	1,154,655

Included within the purchase obligations amount in the table above are annual commitments of approximately $31.4 million relating to the Company’s natural gas distribution and production operations for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years. Approximately $20.0 million of these costs are believed to be recoverable in customer rates.

Operating leases are primarily entered into for various office locations and warehouse buildings, as well as a limited amount of equipment. In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The base rent payments under the new North Shore lease of approximately $2.3 million per year have been included in the table above. The relocation resulted in the early termination of several operating leases for facilities deemed to have no economic benefit to the Company. These obligations, which totaled $10.1 million as of December 31, 2005, are also included in operating lease obligations detailed above.

The other long-term liabilities line represents the total estimated payout for the 2005 Executive Performance Incentive Program. See section titled “Critical Accounting Policies Involving Significant Estimates” and Note 16 to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of this obligation.

Contingent Liabilities and Commitments

At the end of the useful life of a well, the Company is required to remediate the site by plugging and abandoning the well. Costs incurred during 2005, 2004 and 2003 for such activities were not material to the Company and are not expected to be material to operating results in future periods.

The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company. It is the Company’s policy to comply with applicable laws and cooperate when regulatory bodies make requests.

See Note 19 to the Consolidated Financial Statements for further discussion of the Company’s contingent liabilities and commitments.

Cumulative Effect of Accounting Change

Effective January 1, 2003, the Company adopted SFAS No. 143, which requires that the fair value of a liability for an asset retirement obligation be recognized by the Company at the time the obligation is incurred. The adoption of SFAS No. 143 by the Company resulted in an after-tax charge to earnings of $3.6 million, which was reflected as the cumulative effect of accounting change in the Company’s Statement of Consolidated Income for the year ended December 31, 2003.

Critical Accounting Policies Involving Significant Estimates

The Company’s significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. The discussion and analysis of the Consolidated Financial Statements and results of operations are based upon Equitable’s Consolidated Financial Statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed and approved by the Company’s Audit Committee, relate to the Company’s more significant judgments and estimates used in the preparation of its Consolidated Financial Statements. There can be no assurance that actual results will not differ from those estimates.

Allowance for Doubtful Accounts: Equitable Gas encounters risks associated with the collection of its accounts receivable. As such, Equitable Gas records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, Equitable Gas primarily utilizes a historical rate of accounts receivable “write-offs” as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis and is updated periodically based on events that may change the rate, such as a significant increase or decrease in commodity prices or a significant change in the weather. Both of these items ultimately impact the customers’ ability to pay and the rates that are charged to the customers due to the pass-through of purchased gas costs to the customers. Management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.

For 2005, the monthly provision for uncollectible accounts was established at approximately 2% of residential sales, a decrease from the 4% rate utilized for 2004. Beginning in April 2004, the Company began collecting a regulatory surcharge in the amount of $0.30 per Mcfe of gas sold to residential customers to help recover the costs associated with providing gas service to low-income customers. This surcharge is credited to the reserve for uncollectible accounts and reduces the amount which would otherwise be recognized as bad debt expense. This surcharge totaled $6.5 million in 2005 and $3.3 million in 2004. In addition, during 2004, Equitable Gas implemented a new customer information and billing system that has enabled the Company to better segment customer information in order to identify customers who may have difficulty paying. Also, under the Responsible Utility Customer Protection Act which became effective in Pennsylvania in December 2004, Equitable Gas is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and to complete customer terminations without approval from the PA PUC. The Company took advantage of these winter terminations during 2005 in an effort to reduce its uncollectible accounts receivable. Despite the continued increases in natural gas prices throughout 2005, the Company expects to realize a decrease in accounts written off as a result of these initiatives and has consequently reduced its provision for doubtful accounts.

The Company believes that the accounting estimates related to the allowance for doubtful accounts are “critical accounting estimates” because the underlying assumptions used for the allowance can change from period to period and the changes in the allowance could potentially cause a material impact to the income statement and working capital. The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from management’s assumptions and may impact the ultimate collectibility of customer accounts. Additionally, the regulatory environment allows certain customers to enter into long-term payment arrangements, the ultimate collectibility of which is difficult to determine.

Executive Performance Incentive Programs: The Company treats its Executive Performance Incentive Programs as variable plans. The awards under the 2003 Executive Performance Incentive Program vested in December 2005. The actual cost to be recorded for the 2005 Executive Performance Incentive Program (2005 Program) will not be known until the measurement date, which is in December 2008, requiring the Company to estimate the total expense to be recognized. The number of units to be paid out under the 2005 Program is dependent upon a combination of a level of total shareholder return relative to the performance of a peer group and the Company’s average absolute return on capital during the four-year performance period. The Company reviews these assumptions on a quarterly basis and adjusts its accrual for the 2005 Program when changes in these assumptions result in a material change in the value of the ultimate payout. In the current period, the Company

estimated that the performance measures would be met at 175% of the full value of the units for the 2005 Program and that the estimated end of 2008 share price would be $45.00.

The Company believes that the accounting estimate related to the 2005 Program is a “critical accounting estimate” because it is likely to change from period to period based on the market price of the Company’s shares and the performance of the peer group. Additionally, the impact on net income of these changes could be material. Management’s assumptions about future stock price and Company performance relative to the peer group requires significant judgment. Each company’s inherent volatility combined with the volatility in commodity prices impact the ultimate amount of the payout and make it difficult to provide sensitivity metrics to demonstrate what impact a change in the Company’s stock price will have on the estimate. However, assuming no change in the attainment of performance measures, a 10% increase in the Company’s stock price assumptions for December 31, 2008 would result in an increase in 2006 compensation expense under the 2005 Program of approximately $4 million. A 10% decrease in the Company’s stock price assumptions would result in a decrease in 2006 compensation expense of the same amount.

Income Taxes: The Company accounts for income taxes under the provisions of SFAS No. 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Company’s Consolidated Financial Statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Please read Note 6 to the Company’s Consolidated Financial Statements for further discussion.

The Company has recorded deferred tax assets principally resulting from mark-to-market hedging losses recorded in other comprehensive loss, deferred revenues and expenses and state net operating loss carryforwards. The Company has established a valuation allowance against the deferred tax assets related to the state net operating loss carryforwards, as it is believed that it is more likely than not that these deferred tax assets will not all be realized. The Company also recorded a $15.3 million charge in 2005 related to compensation deferred and accrued under certain executive compensation plans, as it was determined that this compensation will not be deductible under Section 162(m) of the IRC. No other valuation allowances have been established, as it is believed that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these assets. Any change in the valuation allowance would impact the Company’s income tax expense and net income in the period in which such a determination is made.

The Company believes that the accounting estimate related to income taxes is a “critical accounting estimate” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that it is believed to be more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about the Company’s current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including the Company’s anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Derivative Commodity Instruments

The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company primarily through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. The Company’s use of derivatives to reduce the effect of this volatility is described in Notes 1 and 3 to the Consolidated Financial Statements and under the caption “Commodity Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations (Item 7) of this Form 10-K. The Company uses simple, non-leveraged derivative commodity instruments that are placed

with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.

For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels, which are exposed to price risk. The financial instruments currently utilized by the Company include futures contracts, swap agreements and collar agreements, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in determining its commodity hedging strategy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. In general, the Company’s strategy is to hedge production at prices considered to be favorable to the Company. The Company attempts to take advantage of price fluctuations by hedging more aggressively when market prices move above historical averages and by taking more price risk when prices are significantly below these levels. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility. To the extent that the Company has hedged its production at prices below the current market price, the Company is unable to benefit fully from increases in the price of natural gas.

For derivative commodity instruments held for trading purposes, the marketing group engages in financial transactions also subject to policies that limit the net positions to specific value at risk limits. The financial instruments currently utilized by the Company for trading purposes include forward contracts and swap agreements.

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of December 31, 2005, the Company had hedged portions of expected equity production through 2012 by utilizing futures contracts, swap agreements and collar agreements covering approximately 311.0 Bcf of natural gas. See the “Commodity Risk Management” and “Capital Resources and Liquidity” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K for further discussion. A decrease of 10% in the market price of natural gas from the December 31, 2005 levels would increase the fair value of natural gas instruments by approximately $268.3 million. An increase of 10% in the market price of natural gas would decrease the fair value by approximately $282.1 million.

With respect to the derivative commodity instruments held by the Company for trading purposes as of December 31, 2005, an increase or decrease of 10% in the market price of natural gas from the December 31, 2005 levels would not have a significant impact on the fair value.

The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal change in fair value as described in Note 1 to the consolidated financial statements. The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2005. The price change was then applied to the derivative commodity instruments recorded on the Company’s balance sheet, resulting in the change in fair value.

The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the unfavorable impact that the same hypothetical price movement would have on the Company and its subsidiaries’ physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.

If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur, or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

Other Market Risks

The Company has variable rate short-term debt. As such, there is some exposure to future earnings due to changes in interest rates. A 100 basis point increase or decrease in interest rates would not have a significant impact on future earnings of the Company under its current capital structure. The Company maintains fixed rate long-term debt that is not subject to risk exposure from fluctuating interest rates.

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX-traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

Statements of Consolidated Income for each of the three years in the period ended December 31, 2005

Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2005

Consolidated Balance Sheets as of December 31, 2005 and 2004

Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2005

Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Equitable Resources, Inc.

We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc. and Subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Asset Retirement Obligations.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Equitable Resources, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2006, expressed an unqualified opinion thereon.

Pittsburgh, Pennsylvania

February 10, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Equitable Resources, Inc.

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting and appearing in the accompanying Item 9A Controls and Procedures, that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Equitable Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Equitable Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005 and our report dated February 10, 2006 expressed an unqualified opinion thereon.

Pittsburgh, Pennsylvania

February 10, 2006

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

YEARS ENDED DECEMBER 31,

	2005		2004			2003
	(Thousands except per share amounts)

Operating revenues	$	1,253,724	$	1,045,183		$	876,574
Cost of sales	511,169		412,050			299,017
Net operating revenues (see Note 1)	742,555		633,133			577,557
Operating expenses:
Operation and maintenance	95,369		87,988			76,319
Production	61,483		43,274			35,687
Selling, general and administrative	140,529		130,090			103,543
Office consolidation impairment chargesImpairment of long-lived assets	7,835		—			—
Depreciation, depletion and amortization	93,527		82,076			76,722
Total operating expenses (see Note 1)	398,743		343,428			292,271
Operating income	343,812		289,705			285,286
Gain on sale of available-for-sale securities, net	110,280		3,024			13,985
Gain on exchange of Westport for Kerr-McGee shares	—		217,212			—
Charitable foundation contribution	—		(18,226		)	(9,279		)
Equity in earnings of nonconsolidated investments:
Westport	—		—			3,614
Other	762		856			580
	762		856			4,194
Other income, net	1,195		3,692			—
Minority interest	—		—			(871		)
Interest expense	44,437		42,520			41,530
Income from continuing operations before income taxes and cumulative effect of accounting change	411,612		453,743			251,785
Income taxes	153,038		154,953			86,035
Income from continuing operations before cumulative effect of accounting change	258,574		298,790			165,750
Income (loss) from discontinued operations, net of tax of $10,485, ($12,259), and ($4,243) for the years ended December 31, 2005, 2004 and 2003, respectively	1,481		(18,936		)	7,807
Cumulative effect of accounting change, net of tax	—		—			(3,556		)
Net income	$	260,055	$	279,854		$	170,001
Earnings per share of common stock:
Basic:
Income from continuing operations before cumulative effect of accounting change	$	2.14	$	2.42		$	1.34
Income from discontinued operations	0.01		(0.15		)	0.06
Cumulative effect of accounting change, net of tax	—		—			(0.03		)
Net income	$	2.15	$	2.27		$	1.37
Diluted:
Income from continuing operations before cumulative effect of accounting change	$	2.09	$	2.37		$	1.31
Income from discontinued operations	0.01		(0.15		)	0.06
Cumulative effect of accounting change, net of tax	—		—			(0.03		)
Net income	$	2.10	$	2.22		$	1.34

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,

	2005			2004			2003
	(Thousands)
Cash flows from operating activities:
Net income	$	260,055		$	279,854		$	170,001
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
(Income) loss from discontinued operations, net of tax	(1,481		)	18,936			(7,807		)
Cumulative effect of accounting change, net of tax.	—			—			3,556
Provision for losses on accounts receivable	8,273			19,659			13,460
Depreciation, depletion and amortization	93,527			82,076			76,722
Gain on sale of available-for-sale securities, net	(110,280		)	(3,024		)	(13,985		)
Office consolidation impairment charges	7,835			—			—
Deferred income taxes	(92,912		)	113,437			67,917
Gain on exchange of Westport for Kerr-McGee shares	—			(217,212		)	—
Charitable foundation contribution	—			18,226			9,279
Recognition of prepaid forward production revenue	—			(10,363		)	(55,705		)
Amendment of prepaid forward contract, net	—			(31,260		)	—
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues	(78,049		)	(69,024		)	(40,103		)
Margin deposits	(280,935		)	(32,463		)	(2,370		)
Inventory	(85,296		)	(45,420		)	(84,757		)
Prepaid expenses and other	(27,564		)	(16,360		)	(9,586		)
Regulatory assets	(2,847		)	506			11,897
Accounts payable	71,451			43,544			15,033
Deferred income taxes	(32,288		)	34,111			2,241
Pension settlements and contributionss	(20,364		)	—			(51,840		)
Changes in other assets and liabilities	29,404			45,901			2,355
Total adjustments	(521,526		)	(48,730		)	(63,693		)
Net cash (used in) provided by continuing operating activities	(261,471		)	231,124			106,308
Net cash (used in) provided by discontinued operating activities	(50,491		)	(51,126		)	22,253
Net cash (used in) provided by operating activities.	(311,962		)	179,998			128,561
Cash flows from investing activities:
Capital expenditures	(275,798		)	(201,813		)	(221,192		)
Purchase of interest in Eastern Seven Partners, L.P.	(57,500		)	—			—
Proceeds from sale of Kerr-McGee shares	460,467			42,880			—
Proceeds from sale of properties	141,991			—			6,550
Proceeds from sale of discontinued operations	80,000			—			—
Investment in available-for-sale securities	(4,009		)	—			—
Purchase of minority interest in Appalachian Basin Partners, L.P	—			—			(44,200		)
Proceeds from sale of Westport stock	—			—			38,419
Net cash provided by (used in) continuing investing activities	345,151			(158,933		)	(220,423		)
Net cash provided by discontinued investing activities.	2,595			439			5,096
Net cash provided by (used in) investing activities	347,746			(158,494		)	(215,327		)
Cash flows from financing activities:
Dividends paid	(99,737		)	(89,364		)	(60,419		)
Purchase of treasury stock	(122,250		)	(118,472		)	(55,235		)
Proceeds from exercises under employee compensation plans	25,016			26,776			39,155
Repayments and retirements of long-term debt	(10,000		)	(20,500		)	(24,316		)
Proceeds from issuance of long-term debt	150,000			—			200,000
Redemption of Trust Preferred Capital Securities	—			—			(125,000		)
Increase in short-term loans	69,801			95,899			93,600
Net cash provided by (used in) continuing financing activities	12,830			(105,661		)	67,785
Net cash provided by discontinued financing activities	26,352			49,863			45,107
Net cash provided by (used in) financing activities	39,182			(55,798		)	112,892
Net increase (decrease) in cash and cash equivalents	74,966			(34,294		)	26,126
Cash and cash equivalents at beginning of year	—			34,294			8,168
Cash and cash equivalents at end of year	$	74,966		$	—		$	34,294
Cash paid during the year for:
Interest (net of amount capitalized)	$	49,085		$	49,656		$	47,212
Income taxes	$	251,486		$	23,043		$	4,661

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2005		2004
	(Thousands)
Assets

Current assets:
Cash and cash equivalents	$	74,966	$	—
Accounts receivable (less accumulated provision for doubtful accounts: 2005, $23,329; 2004, $29,836)	249,397		178,513
Unbilled revenues	58,958		45,905
Margin deposits with financial institutions	317,832		36,897
Inventory	289,921		204,625
Derivative instruments, at fair value	42,899		27,585
Prepaid expenses and other	60,732		33,168
Assets held for sale from discontinued operations	2,518		212,121
Total current assets	1,097,223		738,814
Equity in nonconsolidated investments	35,555		61,625
Property, plant and equipment:
Equitable Utilities	1,155,946		1,087,910
Equitable Supply	2,080,151		1,868,199
Total property, plant and equipment	3,236,097		2,956,109
Less: accumulated depreciation and depletion	1,152,892		1,080,978
Net property, plant and equipment	2,083,205		1,875,131
Investments, available-for-sale	25,194		426,772
Other assets:
Regulatory assets	70,055		67,208
Other	31,053		35,796
Total other assets	101,108		103,004
Total assets	$	3,342,285	$	3,205,346

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2005			2004
	(Thousands)
Liabilities and Common Stockholders’ Equity

Current liabilities:
Current portion of long-term debt	$	3,000		$	10,000
Short-term loans	365,300			295,499
Accounts payable	242,618			171,167
Derivative instruments, at fair value	1,264,204			350,382
Other current liabilities	217,374			134,314
Liabilities held for sale from discontinued operations	—			152,629
Total current liabilities	2,092,496			1,113,991
Debentures and medium-term notes	763,434			616,434
Deferred and other credits:
Deferred income taxes and investment tax credits	24,042			504,389
Other credits	107,845			95,860
Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: 2005 and 2004, 149,008	358,684			356,892
Treasury stock, shares at cost: 2005, 29,102; 2004, 26,946; (net of shares and cost held in trust for deferred compensation of 142, $2,429 and 1,284, $12,303)	(496,511		)	(389,450		)
Retained earnings	1,247,895			1,087,577
Accumulated other comprehensive loss	(755,600		)	(180,347		)
Total common stockholders’ equity	354,468			874,672
Total liabilities and common stockholders’ equity	$	3,342,285		$	3,205,346

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2005, 2004, AND 2003

	Common Stock								Accumulated Other			Common
	Shares Outstanding		No Par Value			Retained Earnings			Comprehensive (Loss) Income			Stockholders’ Equity
	(Thousands)
Balance, December 31, 2002	124,684		$	15,667		$	787,505		$	(24,533	)	$	778,639
Comprehensive income (net of tax):
Net income						170,001						170,001
Net change in cash flow hedges:
Natural gas, net of tax benefit of $38,674 (see Note 3)									(61,140		)	(61,140		)
Interest rate									(133		)	(133		)
Unrealized gain on available-for-sale securities:
Westport (a)									99,630			99,630
Other									2,310			2,310
Minimum pension liability adjustment, net of tax benefit of $448									(869		)	(869		)
Total comprehensive income												209,799
Westport cost basis adjustment (a)			52,857									52,857
Dividends ($0.485 per share)						(60,419		)				(60,419		)
Stock-based compensation plans, net	2,912		39,699									39,699
Stock repurchases	(2,864	)	(55,235		)							(55,235		)
Balance, December 31, 2003	124,732		52,988			897,087			15,265			965,340
Comprehensive income (net of tax):
Net income						279,854						279,854
Net change in cash flow hedges:
Natural gas, net of tax benefit of $82,277 (see Note 3)									(138,926		)	(138,926		)
Interest rate									397			397
Gain on exchange of Westport stock									(143,360		)	(143,360		)
Unrealized gain on available-for-sale securities:
Westport (to date of merger)									43,731			43,731
Kerr-McGee (from date of merger)									36,334			36,334
Other									371			371
Minimum pension liability adjustment, net of tax benefit of $3,009									5,841			5,841
Total comprehensive income												84,242
Dividends ($0.720 per share)						(89,364		)				(89,364		)
Stock-based compensation plans, net	2,030		32,926									32,926
Stock repurchases	(4,700	)	(118,472		)							(118,472		)
Balance, December 31, 2004	122,062		(32,558		)	1,087,577			(180,347		)	874,672
Comprehensive income (net of tax):
Net income						260,055						260,055
Net change in cash flow hedges:
Natural gas, net of tax benefit of $324,817 (see Note 3)									(543,716		)	(543,716		)
Interest rate									97			97
Unrealized gain on available-for-sale securities:
Kerr-McGee									(36,334		)	(36,334		)
Other									375			375
Minimum pension liability adjustment, net of tax benefit of $211									4,325			4,325
Total comprehensive loss												(315,198		)
Dividends ($0.820 per share)						(99,737		)				(99,737		)
Stock-based compensation plans, net	1,412		16,981									16,981
Stock repurchases	(3,568	)	(122,250		)							(122,250		)
Balance, December 31, 2005	119,906		$	(137,827	)	$	1,247,895		$	(755,600	)	$	354,468

Common shares authorized: 320,000,000 shares. Preferred shares authorized: 6,000,000 shares. There are no preferred shares issued or outstanding.

(a) Includes a reclassification of $52.9 million to common stock for the change in accounting treatment of the Company’s investment in Westport from the equity method to available-for-sale, effective March 31, 2003. The Westport shares were subsequently exchanged during 2004 for Kerr-McGee shares (see Note 9). Except for those described in Note 3, there were no other reclassification adjustments for any other categories in 2005, 2004 and 2003.

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2005

1. Summary of Significant Accounting Policies

Principles of Consolidation: The Consolidated Financial Statements include the accounts of Equitable Resources, Inc. and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (“Equitable” or “the Company”). All significant intercompany accounts and transactions have been eliminated in consolidation. Equitable utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.

Reclassification: The Consolidated Financial Statements and related footnote disclosures have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations for all periods presented. See Note 7 for further information. Additionally, certain previously reported amounts have been reclassified to conform to the current year presentation.

Stock Split: On September 1, 2005, the Company effected a two-for-one stock split payable to shareholders of record on August 12, 2005. All share and per share information has been retroactively adjusted to reflect the stock split.

Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.

Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense.

Inventories: The Company’s inventory balance consists of natural gas stored underground and materials and supplies recorded at the lower of average cost or market.

Property, Plant and Equipment: The Company’s property, plant and equipment consists of the following:

	December 31,
	2005		2004
	(Thousands)
Utility plant	$	1,148,063	$	1,085,476
Accumulated depreciation and amortization	392,877		366,124
Net utility plant	755,186		719,352
Gas and oil producing properties, successful efforts method	1,551,677		1,396,898
Accumulated depletion	518,426		488,742
Net oil and gas producing properties	1,033,251		908,156
Other properties, at cost less accumulated depreciation	294,768		247,623
Net property, plant and equipment	$	2,083,205	$	1,875,131

Utility property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2005, and December 31, 2004, was approximately 4% of net Utility properties.

Oil and gas producing properties use the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. The depletion is calculated based on the annual actual production multiplied by the depletion rate per unit.

The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Equitable Supply calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s oil and gas producing properties consists of gas producing properties which were depleted at a rate of $0.59/Mcf and $0.54/Mcf produced for the years ended December 31, 2005, and December 31, 2004, respectively.

The carrying values of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares them to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves utilizing assumptions about the use of the asset and forward market prices for oil and gas. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows are deemed unrecoverable. Those properties are then written down to fair value, which is estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company used forward market prices. For the years ended December 31, 2005, 2004 and 2003, the Company did not recognize impairment charges on oil and gas properties.

Additionally, the costs of unproved oil and gas properties are periodically assessed on a field-by-field basis. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense. For additional information on oil and gas properties, see Note 25 (unaudited).

The Company also had $294.8 million and $247.6 million of other net property at December 31, 2005, and December 31, 2004, respectively. These items are carried at cost and depreciation is calculated using the straight-line method based on estimated service lives. This property consists largely of gathering systems (25 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).

Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.

Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.

Regulatory Accounting: The Company’s distribution operations are subject to comprehensive regulation by the PA PUC and the Public Service Commission of West Virginia. The Company also provides field line service, also referred to as “farm tap” service, in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. The Company’s interstate pipeline operations are subject to regulation by the FERC. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71. The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.

Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company’s Consolidated Balance Sheets as other current assets or liabilities.

When any portion of the Company’s distribution or pipeline operations ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurs.

The following table presents the total regulated net revenue and operating expenses of the Company:

	Years Ended December 31,
	2005		2004		2003
	(Thousands)
Distribution revenues	$	469,102	$	422,438	$	396,203
Pipeline revenues	57,534		55,123		52,926
Total regulated revenue	526,636		477,561		449,129

Distribution purchased gas costs	312,244		263,313		231,017
Pipeline purchased gas costs	3,767		—		—
Total purchased gas costs	316,011		263,313		231,017

Distribution net revenue	156,858		159,125		165,186
Pipeline net revenue	53,767		55,123		52,926
Total regulated net revenue	210,625		214,248		218,112

Distribution operating expenses	116,536		102,248		102,093
Pipeline operating expenses	36,422		30,467		30,511
Total regulated operating expenses	$	152,958	$	132,715	$	132,604

Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the executive vice-president of finance and administration, the chief financial officer and other officers and employees.

The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes and (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities.

All derivative instruments are accounted for in accordance with SFAS No. 133. As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, hedge ineffectiveness is recorded. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available,

measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC. The Company assesses the effectiveness of hedging relationships both at the inception of the hedge and on an on-going basis.

The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of accumulated other comprehensive income (loss) recorded up to that date would remain accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument would be recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income (loss) have been designated and qualify as cash flow hedges. The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with EITF No. 02-3.

Capitalized Interest: Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. Interest costs during 2005, 2004 and 2003 of $0.2 million, $0.1 million and $0.5 million, respectively, were capitalized as a portion of the cost of the related long-term assets.

Impairment of Long-Lived Assets: In accordance with SFAS No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.

Stock-Based Compensation: The Company accounted for its stock options and awards under the intrinsic-value-based method as defined in APB No. 25 for the fiscal years ended December 31, 2005, 2004 and 2003. Accordingly, no compensation cost for fixed stock options is included in net income since all award grants were made at the fair value on the date of grant. Compensation expense for restricted share awards is ratably recognized over the vesting period, based on the fair value of the stock on the date of grant. The Company applies the disclosure provisions of SFAS No. 123 and SFAS No. 148.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to employee stock-based awards. Refer to Note 16 for more information regarding stock-based compensation.

	Year Ended December 31,
	2005			2004			2003
	(Thousands, except per share amounts)
Net income, as reported	$	260,055		$	279,854		$	170,001
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	32,181			20,374			11,879
Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects	(33,693		)	(24,575		)	(18,015		)
Pro Forma net income	$	258,543		$	275,653		$	163,865
Earnings per share:
Basic, as reported	$	2.15		$	2.27		$	1.37
Basic, pro forma	$	2.13		$	2.23		$	1.32

Diluted, as reported	$	2.10		$	2.22		$	1.34
Diluted, pro forma	$	2.09		$	2.18		$	1.29

Revenue Recognition: Sales of natural gas to utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for utility segment revenue whereby revenues applicable to gas delivered to customers but not yet billed under the cycle billing method are estimated and accrued and the related costs are charged to expense. Revenue is recognized for production activities when deliveries of natural gas, crude oil and natural gas liquids are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Revenues from energy marketing activities are recognized when deliveries occur. In accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded using mark-to-market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Company’s natural gas advance sales contracts are recognized as natural gas is gathered and delivered.

Investments: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.

Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale in accordance with SFAS No. 115 and are classified as investments, available-for-sale on the Consolidated Balance Sheets. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other comprehensive income (loss). The Company utilizes the specific identification method to determine the cost of the securities sold.

APB No. 18 requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable. In accordance

with SFAS No. 115, the Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. No other than temporary decline in fair value was recorded in 2005, 2004 or 2003.

Income Taxes: The Company files a consolidated Federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate effective income tax rates are calculated for income from continuing operations, discontinued operations and cumulative effects of accounting changes.

Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities in accordance with SFAS No. 109 which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of such temporary differences. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.

Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.

Allowance for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.

Earnings Per Share (EPS): Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing net income adjusted for the assumed conversion of debt by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and awards. See Note 14 for a detailed calculation.

Asset Retirement Obligations: Effective January 1, 2003, the Company adopted SFAS No. 143, the primary impact of which was to change the method of accruing for well plugging and abandonment costs. These costs were formerly recognized as a component of depreciation, depletion and amortization (DD&A) expense with a corresponding credit to accumulated depletion in accordance with SFAS No. 19. SFAS No. 143 requires that the fair value of the Company’s plugging and abandonment obligations be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company will increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to DD&A, and the initial capitalized costs are depleted over the useful lives of the related assets.

The adoption of SFAS No. 143 by the Company resulted in an after-tax charge to earnings of $3.6 million, or $0.03 per diluted share, which is reflected as a cumulative effect of accounting change in the Company’s Statement of Consolidated Income for the year ended December 31, 2003. In addition to the charge to earnings, the depletion rate in the Company’s Supply segment increased by $0.03 per Mcfe.

The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations. The Company does not have any assets that are legally restricted for purposes of settling these obligations.

	Year ended December 31, 2005
	(Thousands)
Asset retirement obligation as of beginning of period	$	31,857
Accretion expense	2,098
Liabilities incurred	731
Change in well plugging cost assumptions	15,463
Liabilities settled	(4,023		)
Asset retirement obligation as of end of period	$	46,126

Self Insurance: The Company is self-insured for certain losses related to workers’ compensation. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.

Recently Issued Accounting Standards:

Stock Compensation

On December 16, 2004, the FASB issued SFAS No. 123(R) and has issued several subsequent Staff Positions clarifying this guidance. This guidance replaced previously existing requirements under SFAS No. 123 and APB No. 25. Under SFAS No. 123(R), an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award would generally be measured based on the grant-date fair value of the award. The Company will be required to adopt SFAS No. 123(R) in the first quarter of 2006. The Company intends to use the modified prospective method for adoption of SFAS No. 123(R) as permitted by the guidance.

The Company has determined that the impact of SFAS No. 123(R) and related guidance will not be material to its financial statements. In accordance with SFAS No. 123, the Company has historically disclosed the impact on the Company’s net income and earnings per share had the fair value based method been adopted. Had the Company adopted SFAS No. 123(R) in prior periods, the impact of that standard on periods presented in these Consolidated Financial Statements would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share presented earlier in Note 1 under “Stock-Based Compensation.”

Accounting for Uncertain Tax Positions

In July 2005, the FASB issued an exposure draft of a proposed interpretation, “Accounting for Uncertain Tax Positions – an Interpretation of FASB Statement No. 109.” The proposed interpretation would apply to all open tax positions accounted for in accordance with SFAS No. 109, including those acquired in business combinations. In October 2005, the FASB decided to postpone issuance of the final interpretation until fiscal year 2006. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final interpretation is issued.

Earnings Per Share

In September 2005, the FASB issued an exposure draft of a proposed amendment to SFAS No. 128. The proposed amendment would clarify guidance for calculating earnings per share in regards to mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares and contingently issuable shares. Under the exposure draft, the proposed amendment would become effective for the Company in the second quarter of 2006. The Company will evaluate the impact of any change in accounting standard when the final interpretation is issued.

2. Financial Information by Business Segment

Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief executive officer (chief operating decision maker) in deciding how to allocate resources. The Company reports its operations in two segments, which reflect its lines of business. The Equitable Utilities segment’s operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas and limited trading activities. The Equitable Supply segment’s activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil and the extraction and sale of natural gas liquids.

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments, minority interest, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.

	Years Ended December 31,
	2005			2004			2003
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	863,311		$	731,861		$	613,368
Equitable Supply	489,191			390,428			332,434
Less: intersegment revenues (a)	(98,778		)	(77,106		)	(69,228		)
Total	$	1,253,724		$	1,045,183		$	876,574
Total operating expenses:
Equitable Utilities	$	155,110		$	134,556		$	135,244
Equitable Supply	195,610			163,059			136,639
Unallocated expenses (b)	48,023			45,813			20,388
Total	$	398,743		$	343,428		$	292,271
Operating income:
Equitable Utilities	$	98,254		$	108,149		$	109,879
Equitable Supply	293,581			227,369			195,795
Unallocated expenses (b)	(48,023		)	(45,813		)	(20,388		)
Total operating income	$	343,812		$	289,705		$	285,286

	Years Ended December 31,
	2005		2004			2003
	(Thousands)
Reconciliation of operating income to net income:

Equity in earnings of nonconsolidated investments, excluding Westport:
Equitable Supply	$	493	$	688		$	431
Unallocated	269		168			149
Total	$	762	$	856		$	580
Other income, net:
Equitable Supply	$	—	$	576		$	—
Unallocated (c)	1,195		3,116			—
Total	$	1,195	$	3,692		$	—
Minority interest:
Equitable Supply	$	—	$	—		$	(871	)
Total	$	—	$	—		$	(871	)

Gain on sale of available-for-sale securities, net	110,280		3,024			13,985
Gain on exchange of Westport for Kerr-McGee shares	—		217,212			—
Charitable foundation contribution	—		(18,226		)	(9,279		)
Westport equity earnings	—		—			3,614
Interest expense	44,437		42,520			41,530
Income taxes	153,038		154,953			86,035
Income from continuing operations before cumulative effect of accounting change	258,574		298,790			165,750
Income (loss) from discontinued operations	1,481		(18,936		)	7,807
Cumulative effect of accounting change, net of tax (d)	—		—			(3,556		)
Net income	$	260,055	$	279,854		$	170,001

	As of December 31,
	2005		2004
	(Thousands)
Segment assets:
Equitable Utilities	$	1,412,215	$	1,173,374
Equitable Supply	1,844,883		1,416,212
Total operating segments	3,257,098		2,589,586
Headquarters assets, including cash and short-term investments	82,669		403,639
Total operating assets	3,339,767		2,993,225
Assets held for sale from discontinued operations	2,518		212,121
Total assets	$	3,342,285	$	3,205,346

	Years Ended December 31,
	2005			2004		2003
	(Thousands)
Significant noncash expense (income) items:
Equitable Utilities:
Increase in deferred purchased natural gas cost	$	35,806		$	13,270	$	3,553
(Decrease) increase in regulatory asset valuation allowance	(204		)	6,004		—
Impairment charges (e)	3,841			—		—
Equitable Supply:
Impairment charges (e)	519			—		—
Unallocated:
Impairment charges (e)	3,475			—		—
Total	$	43,437		$	19,274	$	3,553
Depreciation, depletion and amortization:
Equitable Utilities	$	27,874		$	25,629	$	27,583
Equitable Supply	64,897			55,836		48,748
Other	756			611		391
Total	$	93,527		$	82,076	$	76,722
Expenditures for segment assets:
Equitable Utilities	$	61,349		$	56,274	$	60,414
Equitable Supply (f)	264,095			141,661		204,527
Other	7,854			3,878		451
Total	$	333,298		$	201,813	$	265,392

(a) Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.

(b) Unallocated expenses consist primarily of certain performance-related incentive costs and administrative costs that are not allocated to the operating segments. For the year ended December 31, 2004, unallocated expenses also include $13.4 million related to the settlement of the cash balance portion of a defined benefit pension plan as more fully discussed in Note 13.

(c) Unallocated other income, net for the years ended December 31, 2005 and 2004 relates to pre-tax dividend income of $1.2 million and $3.1 million, respectively, for the Kerr-McGee Corporation shares held by the Company during those periods.

(d) Net income for the year ended December 31, 2003 has been adjusted to reflect the cumulative effect of an accounting change related to the adoption of Statement No. 143. See Note 1.

(e) The impairment charges for the year ended December 31, 2005 relate to the consolidation of the Company’s administrative operations in a building at the North Shore in Pittsburgh, Pennsylvania. See Note 21.

(f) Capital expenditures for 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P. Capital expenditures for 2003 include $44.2 million for the acquisition of the remaining 31% limited partner interest in Appalachian Basin Partners, L.P. See Note 5.

3. Derivative Instruments

Derivative Commodity Instruments

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from

counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $36.0 million asset and a $1.2 billion liability as of December 31, 2005, and a $26.8 million asset and a $350.4 million liability as of December 31, 2004. These amounts are included in the Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value changed from a net liability of $323.6 million at December 31, 2004 to a net liability of $1.2 billion at December 31, 2005, primarily as a result of the increase in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 383.5 Bcf and 432.6 Bcf as of December 31, 2005 and 2004, respectively, and are primarily related to natural gas swaps. The open positions at December 31, 2005 had maturities extending through December 2012.

The Company had deferred net losses of $741.0 million and $197.3 million in accumulated other comprehensive loss, net of tax, as of December 31, 2005 and 2004, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $267.2 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of December 31, 2005 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions. This recognition occurs through a reduction in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.

During the year ended December 31, 2005, the net change in accumulated other comprehensive loss related to derivatives was a loss of $543.7 million, net of tax. This was comprised of a $147.2 million net realized loss which was reclassified from accumulated other comprehensive loss to earnings and a net unrealized loss of $690.9 million. During the year ended December 31, 2004, the net change in accumulated other comprehensive loss related to derivatives was a loss of $138.9 million, net of tax. This was comprised of a $43.6 million net realized loss which was reclassified from accumulated other comprehensive loss to earnings and a net unrealized loss of $182.5 million. During the year ended December 31, 2003, the net change in accumulated other comprehensive loss related to derivatives was a loss of $61.1 million, net of tax. This was comprised of a $28.8 million net realized loss which was reclassified from accumulated other comprehensive loss to earnings and a net unrealized loss of $89.9 million.

For the years ended December 31, 2005, 2004 and 2003, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges decreased earnings by approximately $0.1 million, $2.0 million and $2.9 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

The Company conducts trading activities through its unregulated marketing group. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy. At December 31, 2005, the absolute notional quantities of the futures and swaps held for trading purposes totaled 9.9 Bcf and 36.4 Bcf, respectively.

Below is a summary of the activity of the fair value of the Company’s derivative commodity contracts with third parties held for trading purposes during the year ended December 31, 2005 (in thousands).

Fair value of contracts outstanding as of December 31, 2004	$	481
Contracts realized or otherwise settled	(1,155		)
Other changes in fair value	344
Fair value of contracts outstanding as of December 31, 2005	$	(330	)

There were no adjustments to the fair value of the Company’s derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the years ended December 31, 2005 and 2004.

The following table presents the maturities and the fair valuation source for the Company’s derivative instruments that were held for trading purposes as of December 31, 2005.

Net Fair Value of Third Party Contract (Liabilities) Assets at Period-End

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)
Prices actively quoted (NYMEX) (1)	$	(452	)	$	359		$	—	$	—	$	(93	)
Prices provided by other external sources (2)	(230		)	(7		)	—		—		(237		)
Net derivative (liabilities) assets	$	(682	)	$	352		$	—	$	—	$	(330	)

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

The overall portfolio of the Company’s energy derivatives held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.

As part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP) as discussed in Note 5, the Company assumed derivative liabilities of $47.3 million for the fair value of ESP’s hedges. These hedges were effectively closed out at acquisition by the purchase of offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. The fair value of these derivative instruments at December 31, 2005 was a $34.0 million liability. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.

In May 2005, the Company sold certain non-core gas properties, as discussed in Note 4. As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at these locations by purchasing offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. The fair value of these derivative instruments at December 31, 2005 was a $20.7 million liability. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.

When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company recorded such deposits in the amount of $267.9 million and $36.0 million in its Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively.

When the Company enters into exchange-traded natural gas contracts, exchanges require participants, including the Company, to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are

subject to change at the exchanges’ discretion. The Company recorded such deposits in the amount of $49.9 million and $0.9 million in its Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. The Company also recorded a liability of $5.1 million in accounts payable as of December 31, 2004, representing amounts received from one of the brokers as a result of the related contracts having a positive fair value.

Other Derivative Instruments

In July 2004, the Company entered into three 7.5 year secured variable share forward transactions. Each transaction had a different counterparty, covered 2.0 million shares of Kerr-McGee Corporation (Kerr-McGee) common stock, contained a collar and permitted receipt of an amount up to the net present value of the floor price prior to maturity. Upon maturity of each transaction, the Company was obligated to deliver to the applicable counterparty, at the Company’s option, no more than 2.0 million Kerr-McGee shares or cash in an equivalent value. The collars effectively limited the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares. A variable portion of the dividends received on the underlying Kerr-McGee shares was paid to each counterparty depending upon the hedged position of such counterparty.

In May 2005, the Company terminated the three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its three counterparties to cover its counterparties’ respective hedged positions. See Note 9 for further discussion of transactions related to the Kerr-McGee shares.

4. Sale of Properties

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for approximately $142 million after purchase price adjustments. In accordance with SFAS No. 19, this sale of only a portion of the Company’s gas properties was treated as a normal retirement with no gain or loss recognized, as doing so did not significantly affect the depletion rate. See Note 25 for further discussion of changes to the Company’s reserves during 2005.

5. Acquisitions

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million.

In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, L.P. (ABP), a partnership that was formed in November 1995 when the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit, for $44.2 million.

See Note 25 for further discussion of changes to the Company’s reserves during 2005.

6. Income Taxes

The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.

	December 31,
	2005			2004
	(Thousands)
Deferred tax liabilities (assets):
Drilling and development costs expensed for income tax reporting	$	328,410		$	311,199
Other comprehensive loss	(455,215		)	(113,558		)
Tax depreciation in excess of book depreciation	140,233			206,557
Regulatory temporary differences	23,375			26,935
Deferred purchased gas cost	10,196			4,657
Deferred compensation plans	(2,235		)	(9,252		)
Charitable contributions	—			(6,421		)
Alternative minimum tax	—			(3,900		)
Investment tax credit	(3,921		)	(4,341		)
Uncollectible accounts	(8,211		)	(12,646		)
Postretirement benefits	(4,348		)	(7,972		)
Kerr-McGee book basis in excess of tax basis	—			105,137
Other	(12,470		)	(11,032		)
Total (including amounts classified as current liabilities of $1,736 and current assets of $7,989 for 2005 and 2004, respectively)	$	15,814		$	485,363

The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2005 was comprised of a $445.7 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $10.4 million deferred tax asset related to the minimum pension adjustment and a $0.9 million deferred tax liability related the Company’s net unrealized gain on available-for-sale securities. The net deferred tax asset relating to the Company’s other comprehensive loss balance as of December 31, 2004 was comprised of a $121.2 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, an $11.0 million deferred tax asset related to the minimum pension adjustment and an $18.6 million deferred tax liability related to the Company’s net unrealized gain on available-for-sale securities.

A significant portion of the decrease in the net deferred tax liability relating to the Company’s tax depreciation in excess of book depreciation from 2004 to 2005 was the result of the Company’s Equitable Supply segment selling certain non-core assets in a taxable transaction in 2005. See Note 4.

Income tax expense is summarized as follows:

	Years Ended December 31,
	2005			2004		2003
	(Thousands)
Current:
Federal	$	237,422		$	39,391	$	17,956
State	8,528			2,125		162
Subtotal	245,950			41,516		18,118
Deferred:
Federal	(92,194		)	113,031		62,320
State	(718		)	406		5,597
Subtotal	(92,912		)	113,437		67,917
Total	$	153,038		$	154,953	$	86,035

Provisions for income taxes differ from amounts computed at the Federal statutory rate of 35% on pretax income from continuing operations before cumulative effect of accounting change. The reasons for the difference are summarized as follows:

	Years Ended December 31,
	2005			2004			2003
	(Thousands)
Tax at statutory rate	$	144,064		$	158,810		$	88,125
State income taxes	5,076			1,645			3,743
Federal tax credits and incentives	(3,604		)	(707		)	(2,095		)
Book/Tax basis differences	(4,410		)	(3,215		)	(4,583		)
Incentive or deferred compensation	15,300			1,400			—
Other	(3,388		)	(2,980		)	845
Income tax expense	$	153,038		$	154,953		$	86,035
Effective tax rate	37.2		%	34.2		%	34.2		%

During 2005, following a moratorium imposed on the Company by the IRS for claiming any research and development (R&D) tax credits, the Company completed an analysis of its R&D expenditures for the years 2001 through 2005. This analysis resulted in a research tax credit that generated a tax benefit of $1.0 million in 2005, net of a tax reserve of $0.5 million.

During 2005, the Qualified Production Activities Deduction under Section 199 of the IRC, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004 (Jobs Act). The Company recorded an income tax benefit for certain qualifying production activities of approximately $1.9 million in 2005.

During 2005, the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily as the result of impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.

During 2003, the Company requested permission to change its method of accounting for inventory and self-constructed property in accordance with IRC Section 263A to use the simplified service cost method and simplified production method of capitalizing costs. The request is pending approval. During 2005, the IRS and the U.S. Treasury Department issued guidance providing for further clarification indicating that certain self-constructed property does not qualify as eligible property for the simplified methods. In January 2006, the Company requested permission to conform its capitalization method to recent guidance and the request is pending approval. Consequently, the Company reclassified the deferred tax liability recorded as a result of the 2003 proposed method change to current taxes payable and believes that it is appropriately reserved for any tax exposures related to this item.

The consolidated Federal income tax liability of the Company has been settled with the IRS through 1997. The IRS has substantially completed its review of the Company’s Federal income tax filings for the 1998 through 2000 years and is in the process of preparing its report to the Joint Committee on Taxation (a joint committee of Congress). The Joint Committee on Taxation must approve the findings due to a refund claim in excess of $2 million. The IRS is expected to review the Company’s Federal income tax filings for the 2001 through 2004 tax years beginning in 2006. The Company also is the subject of various routine state income tax examinations. The Company believes that it is appropriately reserved for any tax exposures.

An income tax benefit of $18.0 million, $7.8 million and $9.3 million for the years ended December 31, 2005, 2004 and 2003, respectively, triggered by the exercise of nonqualified employee stock options and vesting of restricted share awards is reflected as an addition to common stockholders’ equity.

The Company has recorded a deferred tax asset of $10.9 million, net of valuation allowances of $9.6 million, related to tax benefits from state net operating loss carryforwards with various expiration dates.

7. Discontinued Operations

In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments of $2 million, which resulted in the Company receiving $80 million of proceeds in December 2005 for this sale. The sales price is also subject to future customary purchase price adjustments per the terms of the agreement. As a result of this sale, the Company recorded after-tax charges totaling $18.7 million, including $13.7 million which relates to the recording of income taxes associated with the difference between the book and tax basis of the NORESCO assets sold, and $5.0 million of after-tax losses on the sale related to other costs incurred as a result of this sale. These charges are included in income from discontinued operations. The Company has recorded a liability of $12.3 million in other current liabilities in its Consolidated Balance Sheet as of December 31, 2005 for its estimated obligations, excluding the tax charge, under this sale agreement. This amount includes an estimate of amounts due to the purchaser for purchase price adjustments. Under the stock purchase agreement, the Company also agreed to maintain certain guarantees previously in place and to issue certain additional guarantees related to NORESCO’s future performance on certain contracts. See Note 20 for further discussion.

Also in December 2005, the Company entered into a purchase and sale agreement, subject to closing conditions, to sell the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am) for $2.5 million, and as the sale is expected to close in 2006, the Company considers the investment to be held for sale. The Company recognized a tax benefit of $6.4 million in the fourth quarter of 2005 as a result of the reorganization of the international operations. The Company recorded the Pan Am investment at its fair value as of December 31, 2005, resulting in an impairment charge of $0.2 million included in income from discontinued operations.

As a result of these transactions, the Company has reclassified its financial statements for all periods presented to reflect the operating results of the NORESCO segment as discontinued operations.

The results of the NORESCO discontinued operations for the fiscal years ended December 31, 2005, 2004 and 2003 are summarized as follows:

	NORESCO DOMESTIC									NORESCO INTERNATIONAL
	Years Ended December 31,									Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	(Thousands)									(Thousands)
Net operating revenues	$	36,575		$	39,336		$	41,014		$	—		$	—		$	—
Operating expenses	24,522			23,569			23,482			—			821			601
Earnings (losses) from nonconsolidated investments, including impairments	43			38			343			14,469			(38,476		)	(8,932		)
Minority interest	(934		)	(976		)	(542		)	—			—			—
Loss on sale of discontinued operations	(7,764		)	—			—			—			—			—
Interest expense	5,901			6,727			3,377			—			—			859
Income (loss) before income taxes	(2,503		)	8,102			13,956			14,469			(39,297		)	(10,392		)
Income tax expense (benefit)	11,808			1,503			(610		)	(1,323		)	(13,762		)	(3,633		)
Net income (loss)	$	(14,311	)	$	6,599		$	14,566		$	15,792		$	(25,535	)	$	(6,759	)

Interest expense of discontinued operations includes interest related to long-term debt and project financing obligations recorded under liabilities held for sale during the years presented as well as an allocation of other interest expense based upon a ratio of the net assets of the discontinued operations to the overall net assets of the Company.

Total interest expense allocated using this method was $1.5 million, $1.5 million, and $1.2 million for the years ended December 31, 2005, 2004, and 2003, respectively. Other Company interest expense was not allocated to the international operations, as the Company did not contribute any capital to those operations during 2003, 2004 or 2005.

At December 31, 2005 and 2004, the major components of assets and liabilities of the NORESCO discontinued operations were as follows:

	NORESCO DOMESTIC				NORESCO INTERNATIONAL
	December 31,				December 31,
	2005		2004		2005		2004
	(Thousands)				(Thousands)
Accounts receivable and unbilled revenues	$	—	$	126,305	$	18	$	—
Equity in nonconsolidated investments	—		103		2,500		2,828
Property, plant and equipment, net	—		4,656		—		—
Goodwill	—		51,656		—		—
Other assets	—		19,583		—		6,990
Total assets	$	—	$	202,303	$	2,518	$	9,818

Project financing obligations	$	—	$	104,610	$	—	$	—
Other liabilities	—		32,987		—		15,032
Total liabilities	$	—	$	137,597	$	—	$	15,032

Cash flows generated from the discontinued operations and the proceeds received from the sale of the discontinued NORESCO Domestic operations of $80.0 million are presented on the consolidated statements of cash flows within these Consolidated Financial Statements.

8. Equity in Nonconsolidated Investments

The Company has ownership interests in various nonconsolidated investments that are accounted for under the equity method of accounting. The following table summarizes the equity in nonconsolidated investments.

		Interest	Ownership as of December		December 31,
Investees	Location	Type	31, 2005		2005		2004
					(Thousands)
Appalachian Natural Gas Trust (ANGT)	USA	Limited	1	%	$	35,555	$	35,616
ESP	USA	Limited	100	%	—		26,009
Total equity in nonconsolidated investments					$	35,555	$	61,625

The Company did not make any additional equity investments in nonconsolidated investments during 2005 or 2004 and has a total cumulative investment in nonconsolidated entities of $35.6 million as of December 31, 2005. The Company’s ownership share of the earnings for 2005, 2004 and 2003 related to the total investments, excluding Westport, was $0.8 million, $0.9 million and $0.6 million, respectively.

Equitable Supply’s equity investment in ANGT represents an ownership interest in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. In 2002, Equitable Supply transferred one-third of its ownership in ANGT to an affiliated company. As of both December 31, 2005 and 2004, Equitable Supply’s investment in ANGT totaled $23.7 million, while the Company’s total investment was $35.6 million.

As discussed in Note 5, the Company purchased the 99% limited partnership interest in ESP in January 2005. The financial position and results of operations of ESP have been consolidated in the Company’s Consolidated Financial Statements as of and for the year ending December 31, 2005.

The following tables summarize the financial information for nonconsolidated investments accounted for under the equity method of accounting:

Summarized Balance Sheets

	As of December 31,
	2005		2004
	(Thousands)
Current assets	$	15,057	$	26,615
Noncurrent assets	206,145		287,784
Total assets	$	221,202	$	314,399

Current liabilities	$	17	$	17
Stockholders’ equity	221,185		314,382
Total liabilities and stockholders’ equity	$	221,202	$	314,399

Summarized Statements of Income

	Year Ended December 31,
	2005		2004		2003
	(Thousands)
Revenues	$	111,037	$	125,323	$	117,174
Costs and expenses applicable to revenues	—		—		—
Net revenues	111,037		125,323		117,174
Operating expenses	39,441		67,825		60,298
Net income	$	71,596	$	57,498	$	56,876

9. Investments

As of December 31, 2005, the investments classified by the Company as available-for-sale consist of approximately $25.2 million of equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.

Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss.

Information regarding the cost and fair value of the Company’s available-for-sale investments at December 31, 2005 and December 31, 2004 is presented in the tables below.

	December 31, 2005
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(Thousands)
Corporate equity securities	$	22,742	$	2,452	$	—	$	25,194
Total investments	$	22,742	$	2,452	$	—	$	25,194

	December 31, 2004
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(Thousands)
Investment in Kerr-McGee	$	350,128	$	56,012	$	—		$	406,140
Other corporate equity securities	11,054		1,954		—			13,008
Corporate notes and bonds	7,751		—		(127		)	7,624
Total investments	$	368,933	$	57,966	$	(127	)	$	426,772

In May 2005, the three variable share forward transactions associated with Kerr-McGee shares were terminated as described in Note 3. The Company concurrently sold 4.3 million Kerr-McGee shares to its three counterparties and received $227.4 million in pre-tax net proceeds at an average price of $75.43 per share. In addition, the Company unconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGee’s Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49.0 million in pre-tax proceeds on the sale of approximately 0.6 million shares. These transactions resulted in pre-tax gains to the Company totaling $34.2 million, net of collar termination costs.

In various transactions during 2005, the Company sold its remaining approximately 2.1 million Kerr-McGee shares for total pre-tax proceeds of $184.1 million. The sale of these shares resulted in pre-tax gains to the Company totaling $76.1 million. The Company has no further interest or ownership in any Kerr-McGee shares.

The Company recorded pre-tax dividend income, net of payments to the counterparties for the aforementioned collars, of $1.2 million and $3.1 million for the years ended December 31, 2005 and 2004, respectively. This dividend income is recorded in other income, net on the Statements of Consolidated Income.

Under the terms of the merger agreement between Westport and Kerr-McGee, the Company received 0.71 shares of Kerr-McGee for each Westport share owned, or 8.2 million shares of Kerr-McGee, in the second quarter of 2004. Accordingly, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares in 2004.

Subsequent to the Kerr-McGee/Westport merger, the Company sold 0.8 million Kerr-McGee shares for pre-tax proceeds of $42.9 million in 2004. The sale resulted in the Company recognizing a gain of $3.0 million in 2004.

In 2004, the Company contributed approximately 0.4 million Kerr-McGee shares to Equitable Resources Foundation, Inc. This resulted in the Company recording a charitable foundation contribution expense of $18.2 million during 2004, with a corresponding one-time tax benefit of $6.8 million.

The Company utilizes the specific identification method to determine the cost of all investment securities sold.

10. Regulatory Assets

The following table summarizes the Company’s regulatory assets, net of amortization, as of December 31, 2005 and 2004. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets.

	December 31,
Description	2005			2004
	(Thousands)
Deferred taxes	$	56,208		$	62,117
Delinquency Reduction Opportunity Program	7,449			10,404
Other postemployment benefits (SFAS No. 106)	8,626			7,530
Deferred purchase gas costs	50,472			14,666
Other	172			161
Valuation allowance	(2,400		)	(13,004		)
Total regulatory assets	120,527			81,874
Amounts classified as other current assets	50,472			14,666
Total long-term regulatory assets	$	70,055		$	67,208

The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company is recovering the amortization of this asset through rates. The Company had established a valuation allowance of $10.4 million as of December 31, 2004, against the deferred tax regulatory asset. During 2005, the Company evaluated the collectibility of the deferred tax regulatory asset through future rates. As a result, $8.3 million of the valuation allowance was utilized to record the deferred tax regulatory asset at the amount deemed collectible. The remaining $2.1 million valuation allowance was included as a component of the Company’s effective tax rate.

The regulatory asset associated with a Delinquency Reduction Opportunity Program was recognized as of December 31, 2001, at Equitable Gas and relates to uncollectible accounts receivable resulting from unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was initially established based upon the Company’s ability to recover these costs through a surcharge in rates. In 2002, the PA PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments that exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customer’s delinquent balance. This program is funded through customer contributions and through the existing surcharge in rates. The Company has established a valuation allowance of $2.4 million and $2.6 million as of December 31, 2005 and 2004, respectively, against the Delinquency Reduction Opportunity Program asset.

The following regulatory assets do not earn a return on investment: deferred taxes, Delinquency Reduction Opportunity Program and other postemployment benefits (SFAS No. 106). The associated remaining recovery period for the regulatory assets associated with both the Delinquency Reduction Opportunity Program and other postemployment benefits is 10 years. The associated remaining recovery period for the regulatory assets associated with deferred taxes is variable depending on the life of the book/tax difference generating the deferred item.

11. Short-Term Loans

On August 11, 2005, the Company entered into a $650 million, five-year revolving credit agreement, which replaced the Company’s previous $500 million, three-year revolving credit agreement. On December 14, 2005, the Company entered into an amendment to the five-year revolving credit agreement. The amendment increased the lenders’ aggregate commitment from $650 million to an aggregate of $1 billion and extended the stated maturity date from August 9, 2006 to August 10, 2010. The Company may request a separate one-year extension of the maturity date between each of June 11, 2006, through September 9, 2006, and June 11, 2007,

through September 9, 2007. The credit agreement may be used for working capital, capital expenditures, share repurchases and other lawful purposes including support of the Company’s commercial paper program. Subject to certain terms and conditions, the Company may, on a one-time basis, request that the lender’s commitments be increased to an aggregate amount of up to $1.5 billion.

The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by either Standard & Poor’s or Moody’s on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate. As of December 31, 2005, the Company had not borrowed any amounts against these lines of credit. Commitment fees averaging one-thirteenth and one-eleventh of one percent in 2005 and 2004, respectively, were paid to maintain credit availability.

Short-term loans were comprised of commercial paper balances of $365.3 million and $295.5 million with weighted average annual interest rates of 4.40% and 2.33% as of December 31, 2005 and 2004, respectively. The maximum amount of outstanding short-term loans at any time during the year was $631.5 million in 2005 and $397.5 million in 2004. The average daily balance of short-term loans outstanding over the course of the year was approximately $309.6 million and $185.2 million at weighted average annual interest rates of 3.48% and 1.65% during 2005 and 2004, respectively.

12. Long-Term Debt

	December 31,
	2005		2004
	(Thousands)
5.15% notes, due March 1, 2018	$	200,000	$	200,000
5.15% notes, due November 15, 2012	200,000		200,000
5.00% notes, due October 1, 2015	150,000		—
7.75% debentures, due July 15, 2026	115,000		115,000
Medium-term notes:
8.4% to 9.0% Series A, due 2006 thru 2021	53,434		53,434
7.3% to 7.6% Series B, due 2013 thru 2023	30,000		40,000
6.8% to 7.6% Series C, due 2007 thru 2018	18,000		18,000
	766,434		626,434
Less debt payable within one year	3,000		10,000
Total long-term debt	$	763,434	$	616,434

On September 30, 2005, the Company issued $150 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015. The notes were approved by the PA PUC on October 27, 2005. The effective annual interest rate on the $150 million of notes is 5.06%.

As of December 31, 2005, the Company has the ability to issue $100 million of additional long-term debt under the provisions of shelf registrations filed with the Securities and Exchange Commission.

The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Company’s debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.

Aggregate maturities of long-term debt are $3.0 million in 2006, $10.0 million in 2007, $0 in 2008, $4.3 million in 2009 and $0 in 2010.

13. Pension and Other Postretirement Benefit Plans

During 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, which was accounted for under SFAS No. 88, the Company recognized a settlement expense of $12.1 million during 2005. During the fourth quarter of 2005, the Company settled its pension obligation with certain non-represented employees. As a result of this settlement, which was accounted for under SFAS No. 88, the Company recognized a settlement expense of approximately $2.4 million in 2005.

These settlement expenses were primarily the result of accelerated recognition of unrecognized losses. Under these settlements, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan or to receive an insured monthly annuity benefit at the time they retire. Additionally, $14.3 million of these pension settlement expenses are recorded as a selling, general and administrative expense within operating expense of the Equitable Utilities business segment, and $0.2 million is a gathering and compression expense included within operating expense of the Equitable Supply business segment (see Note 2). As a result of these settlements, the Company’s projected benefit obligation decreased by approximately $13.9 million.

All other non-represented employees are participants in a defined contribution plan.

Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees (cash balance participants) whose benefits were frozen as of December 31, 2003. As a result of this settlement, the Company recognized a one-time settlement expense of $13.4 million in 2004, which was primarily the result of accelerated recognition of previously deferred unrecognized losses. The pension settlement expense in 2004 is recorded as an unallocated expense in deriving total operating income for segment reporting purposes (see Note 2). As a result of this settlement, the Company’s projected benefit obligation decreased by approximately $19.6 million.

The following table sets forth the defined benefit pension and other postretirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets:

	Pension Benefits						Other Benefits
	2005			2004			2005			2004
	(Thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	116,255		$	116,947		$	55,673		$	52,769
Service cost	899			1,590			541			483
Interest cost	5,891			6,970			3,168			3,273
Amendments	—			—			1,248			—
Actuarial loss	7,883			5,038			675			6,445
Benefits paid	(7,605		)	(7,821		)	(7,048		)	(7,297		)
Expenses paid	—			(352		)	—			—
Curtailments	1,048			2,434			—			—
Settlements	(42,218		)	(8,551		)	—			—
Benefit obligation at end of year	$	82,153		$	116,255		$	54,257		$	55,673

	Pension Benefits						Other Benefits
	2005			2004			2005			2004
	(Thousands)
Change in plan assets:
Fair value of plan assets at beginning of year	$	100,917		$	108,311		$	—		$	—
Gain recognized at beginning of year	41			3			—			—
Actual gain on plan assets	3,580			8,917			—			—
Employer contribution	20,364			—			—			—
Benefits paid	(7,605		)	(7,821		)	—			—
Expenses paid	—			(352		)	—			—
Settlements	(42,218		)	(8,141		)	—			—
Fair value of plan assets at end of year	$	75,079		$	100,917		$	—		$	—
Funded status	$	(7,074	)	$	(15,338	)	$	(54,257	)	$	(55,673	)
Unrecognized net actuarial loss	25,721			29,835			39,619			41,242
Unrecognized prior service cost (credit)	1,863			4,316			842			(448		)
Net amount recognized	$	20,510		$	18,813		$	(13,796	)	$	(14,879	)
Amounts recognized in the statement of financial position consist of:
Accrued benefit liability	$	(7,074	)	$	(15,338	)	$	(13,796	)	$	(14,879	)
Intangible asset	1,863			4,316			—			—
Accumulated other comprehensive loss	15,366			19,691			—			—
Deferred tax asset	10,355			10,144			—			—
Net amount recognized	$	20,510		$	18,813		$	(13,796	)	$	(14,879	)

The accrued pension benefit liability of $7.1 million and $15.3 million as of December 31, 2005 and 2004, respectively, is included in other credits on the Consolidated Balance Sheets. The accrued benefit liability for other postretirement benefits of $13.8 million and $14.9 million as of December 31, 2005 and 2004, respectively, is also included in other credits. A total of $4.3 million was included in other comprehensive loss in 2005 as a result of the change in the additional minimum pension liability from December 31, 2004 to December 31, 2005. The accumulated benefit obligation for all defined benefit pension plans was $82.2 million and $116.3 million at December 31, 2005 and 2004, respectively.

The Company uses a December 31 measurement date for its defined benefit pension and other postretirement plans.

The Company’s costs related to its defined benefit pension and other postretirement benefit plans were as follows:

	Pension Benefits									Other Benefits
	2005			2004			2003			2005			2004			2003
	(Thousands)
Components of net periodic benefit cost:
Service cost	$	899		$	1,590		$	2,684		$	541		$	483		$	313
Interest cost	5,891			6,970			7,553			3,168			3,273			3,467
Expected return on plan assets	(8,032		)	(9,828		)	(8,660		)	—			—			—
Amortization of prior service cost	766			940			1,286			(42		)	(42		)	(42		)
Amortization of initial net obligation	—			—			—			—			—			—
Recognized net actuarial loss	867			745			21			2,299			2,000			1,828
Special termination benefits	88			—			—			—			—			—
Settlement loss (a)	15,625			13,733			2,206			—			—			—
Curtailment loss	2,648			2,434			2,181			—			—			—
Net periodic benefit cost	$	18,752		$	16,584		$	7,271		$	5,966		$	5,714		$	5,566

(a) The 2005 settlement loss includes $10.4 million of loss recognition for the settlement of the Steelworkers pension benefit obligation and $1.3 million of loss associated with the non-represented employees portion of the pension benefit obligation which was settled during the fourth quarter of 2005. The 2004 settlement loss includes $11.0 million of loss recognition associated with the settlement of the cash balance participants pension benefit obligation at December 31, 2004, for those non-represented employees whose benefits under the pension plan were frozen in 2003.

The following weighted average assumptions were used to determine the benefit obligations and net periodic benefit cost for the Company’s defined benefit pension and other postretirement benefit plans:

	Pension Benefits				Other Benefits
	2005		2004		2005		2004

Discount rate	5.75	%	6.00	%	5.75	%	6.00	%
Expected return on plan assets	8.25	%	8.25	%	N/A		N/A
Rate of compensation increase	N/A		N/A		N/A		N/A

The expected rate of return is established at the beginning of the fiscal year that it relates to based upon information available to the Company at that time, including the plans’ investment mix and the forecasted rates of return on these types of securities. The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost in accordance with SFAS No. 87. The expected rate of return determined as of January 1, 2006 totaled 8.25%. This assumption will be used to derive the Company’s 2006 net periodic benefit cost. The rate of compensation increase is no longer applicable in determining future benefit obligations as a result of the conversion of certain non-represented employees to a defined contribution plan in 2003 as previously discussed.

For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2006 is 8.0% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 4.5% in 2009.

Assumed health care cost trend rates have an 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:

	One-Percentage-Point Increase						One-Percentage-Point Decrease
	(Thousands)						(Thousands)
	2005		2004		2003		2005			2004			2003
Increase (decrease) to total of service and interest cost components	$	91	$	108	$	87	$	(90	)	$	(104	)	$	(81	)
Increase (decrease) to postretirement benefit obligation	$	2,030	$	1,751	$	1,407	$	(1,897	)	$	(1,659	)	$	(1,316	)

The Company’s pension asset allocation at December 31, 2005 and 2004 and target allocation for 2006 by asset category are as follows:

	Target	Percentage of Plan Assets at December 31,
Asset Category	Allocation 2006	2005		2004

Domestic broadly diversified equity securities	50% - 70%	54	%	56	%
Fixed income securities	30% - 45%	38	%	37	%
International broadly diversified equity securities	0% - 10%	7	%	6	%
Other	0% - 15%	1	%	1	%
		100	%	100	%

The investment activities of the Company’s pension plan are supervised and monitored by the Company’s Benefits Investment Committee. The Benefits Investment Committee has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Benefits Investment Committee are to minimize high levels of risk at the total pension investment fund level. The Benefits Investment Committee monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.

The Company made cash contributions of approximately $20.4 million to its pension plan during 2005, of which $12.6 million was to fund the cash balance participants’ portion of the pension plan and $7.8 million was to fund the Steelworkers portion of the pension plan. The Company expects to make a cash contribution of approximately $2.3 million to its pension plan during 2006 to fund the non-represented employees’ portion of the pension plan which was settled during the fourth quarter of 2005.

The Company was not required to, and consequently did not make any contribution to its pension plans during the year ended December 31, 2004. The Company made cash contributions totaling $51.8 million to its pension plan during the year ended December 31, 2003, primarily due to the Company’s benefit obligation being significantly under funded.

The following benefit payments, which reflect expected future service, are expected to be paid during each of the next five years and the five years thereafter: $10.2 million in 2006; $7.4 million in 2007; $7.2 million in 2008; $7.2 million in 2009; $6.6 million in 2010; and $33.2 million in the five years thereafter.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the MPDIM Act) was signed into law. The MPDIM Act expanded Medicare to include coverage for prescription drugs. In accordance with FSP FAS 106-2, all measures of the accumulated postretirement benefit obligation and net periodic postretirement benefit cost in the financial statements and accompanying notes reflect the impact of the MPDIM Act on the Company’s postretirement benefit plan for the entire 2005 fiscal year.

The Company sponsors two Medicare supplement retiree medical programs which are impacted by the MPDIM Act. Initially, the Company planned to take advantage of the federal subsidy provided to employers that provide a prescription drug benefit that is at least actuarially equivalent to the program provided through Medicare Part D. However, in the fourth quarter of 2005, it was determined that the Company would not take advantage of the federal subsidy and, as a better alternative, plan design changes were made that benefited both the Company and retiree plan participants. As a result of the plan design changes, the accumulated postretirement benefit obligation and the net periodic postretirement benefit cost were reduced by $3.4 million and $0.5 million, respectively.

Expense recognized by the Company related to its 401(k) employee savings plans totaled $5.1 million in 2005, $4.5 million in 2004 and $3.1 million in 2003.

14. Common Stock and Earnings Per Share

At December 31, 2005, shares of Equitable’s authorized and unissued common stock were reserved as follows:

		(Thousands)

Possible future acquisitions		13,194
Stock compensation plans		16,339
Total		29,533

Earnings Per Share

The computation of basic and diluted earnings per common share is shown in the table below:

	Years Ended December 31,
	2005		2004			2003
	(Thousands, except per share amounts)
Basic earnings per common share:
Income from continuing operations before cumulative effect of accounting change	$	258,574	$	298,790		$	165,750
Income (loss) from discontinued operations, net of tax	1,481		(18,936		)	7,807
Cumulative effect of accounting change, net of tax	—		—			(3,556		)
Net income applicable to common stock	$	260,055	$	279,854		$	170,001
Average common shares outstanding	121,099		123,364			124,100
Basic earnings per common share	$	2.15	$	2.27		$	1.37
Diluted earnings per common share:
Income from continuing operations before cumulative effect of accounting change	$	258,574	$	298,790		$	165,750
Income (loss) from discontinued operations, net of tax	1,481		(18,936		)	7,807
Cumulative effect of accounting change, net of tax	—		—			(3,556		)
Net income applicable to common stock	$	260,055	$	279,854		$	170,001
Average common shares outstanding	121,099		123,364			124,100
Potentially dilutive securities:
Stock options and awards (a)	2,616		2,838			2,616
Total	123,715		126,202			126,716
Diluted earnings per common share	$	2.10	$	2.22		$	1.34

(a) There were no antidilutive options for 2005 or 2004. Options to purchase 22,674 shares of common stock were not included in the computation of diluted earnings per common share for 2003 because the options’ exercise prices were greater than the average market prices of the common shares.

15. Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss, net of tax, are as follows:

	2005			2004
	(Thousands)

Net unrealized loss from hedging transactions	$	(741,804	)	$	(198,185	)
Unrealized gain on available-for-sale securities	1,570			37,529
Minimum pension liability adjustment	(15,366		)	(19,691		)
Accumulated other comprehensive loss	$	(755,600	)	$	(180,347	)

16. Stock-Based Compensation Plans

Long-Term Incentive Plans

The Company’s 1994 and 1999 Long-Term Incentive Plans (the Plans) provide for the granting of shares of common stock to officers and key employees of the Company. These grants may be made in the form of restricted stock, stock options, stock appreciation rights and other types of stock-based or performance-based awards as determined by the Compensation Committee of the Board of Directors at the time of each grant. Stock awarded under the Plans and the value of stock appreciation units are restricted and subject to forfeiture should an optionee terminate employment prior to specified vesting dates. In no case may the number of shares granted under the Plans exceed 6,902,000 and 22,000,000 shares, respectively. Options granted under the Plans expire 6 to 10 years from the date of grant and some contain vesting provisions that are based upon the Company’s performance. As of December 31, 2005, no options were outstanding or exercisable under the 1994 Long-Term Incentive Plan. No new stock options have been awarded since 2003. Option grants reflected below for 2004 and 2005 comprise options granted for reload rights associated with previously awarded options.

Restricted Stock Awards

In 2005, 2004 and 2003, the Company granted 138,400, 291,100 and 141,020 restricted stock awards, respectively, to key employees from the 1999 Long-Term Incentive Plan. The weighted average fair value per share of these restricted stock grants is $33.07, $21.88 and $17.80, respectively, for 2005, 2004 and 2003. The shares granted under these plans will be fully vested at the end of the three-year period commencing the date of grant. Compensation expense recorded by the Company related to restricted stock awards was $3.4 million in 2005, $3.8 million in 2004 and $2.6 million in 2003. A total of 520,435 restricted stock awards were outstanding as of December 31, 2005.

A summary of restricted stock activity as of December 31, 2005, and changes during the year then ended, is presented below:

Restricted Stock	Non- Vested Shares		Weighted Average Fair Value		Weighted Average Remaining Contractual Term (months)	Aggregate Fair Value

Outstanding at January 1, 2005	594,180		$	19.35		$	11,494,897

Granted	138,400		$	33.07		$	4,576,848

Vested	(112,660	)	$	16.02		$	(1,804,472	)

Forfeited	(99,485	)	$	24.02		$	(2,389,378	)

Outstanding at December 31, 2005	520,435		$	22.82	16.6	$	11,877,895

Executive Performance Incentive Programs

In the first quarter of 2005, the Company paid out the 552,000 performance-based stock units that vested December 31, 2004, under the Company’s 2002 Executive Performance Incentive Program. This payment totaled $16.7 million.

The vesting of performance-based stock units granted under the 2003 Executive Performance Incentive Program (2003 Program) occurred on December 30, 2005, after the ordinary close of the performance period and resulted in approximately 1.3 million units (167% of the award) being distributed in cash on that date. This payment totaled $51.0 million. The 2003 Program expense for the period ended December 31, 2005, was $21.3 million and is classified as selling, general and administrative expense.

In February 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long-Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. A total of 1,066,800 stock units were granted to thirty-seven participants. No additional units may be granted. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to the 29 peer companies identified below and the Company’s average absolute return on total capital during the four-year performance period. As a result, zero to 2,667,000 units (250% of the units available for grant) may be distributed in cash or stock. The Company anticipates, based on current estimates, that a certain level of performance will be met and has expensed a ratable estimate of the units accordingly. The 2005 Program expense for the period ended December 31, 2005, was $22.5 million and is classified as selling, general and administrative expense.

The current peer companies for the 2005 Program are as follows:

AGL Resources Inc.	MDU Resources Group Inc.	Questar Corp.
ATMOS Energy Corp.	National Fuel Gas Co.	Sempra Energy
Cascade Natural Gas Corp.	New Jersey Resources Corp.	Southern Union Co.
CMS Energy Corp.	NICOR, Inc.	Southwest Gas Corp.
Dynegy Inc.	NISOURCE Inc.	Southwestern Energy Co
El Paso Corp.	Northwest Natural Gas Co.	UGI Corp.
Energen Corp.	OGE Energy Corp.	Westar Energy Inc.
Keyspan Corp.	ONEOK Inc	WGL Holdings, Inc.
Kinder Morgan Inc.	Peoples Energy Corp.	The Williams Companies, Inc.
Laclede Group, Inc.	Piedmont Natural Gas Co., Inc.

Stock Options

Pro forma information regarding net income and earnings per share for options granted is required by SFAS No. 123 and has been determined as if the Company had accounted for its employee stock options under the fair value method of SFAS No. 123. See Note 1. The fair value for these option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the following assumptions for 2005, 2004 and 2003, respectively.

	Years Ended December 31,
	2005			2004			2003

Risk-free interest rate (range)	3.74% to 4.34		%	1.95% to 4.34		%	2.35% to 3.72		%
Dividend yield	2.44		%	2.88		%	2.47		%
Volatility factor	.274			.263			.251
Weighted average expected life of options	7 years			7 years			7 years
Options granted	68,898			126,858			1,081,830
Weighted average fair market value of options granted during the year	$	7.65		$	4.94		$	4.84

	Years Ended December 31,
	2005				2004				2003
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Options outstanding January 1	7,610,098		$	14.56	9,776,016		$	14.23	12,332,008		$	13.28
Granted	68,898		$	31.03	126,858		$	23.36	1,081,830		$	18.07
Forfeited	(72,574	)	$	18.38	(164,468	)	$	17.33	(453,146	)	$	17.06
Exercised	(2,496,001	)	$	11.30	(2,128,308	)	$	13.35	(3,184,676	)	$	11.45
Options outstanding December 31	5,110,421		$	16.32	7,610,098		$	14.56	9,776,016		$	14.23
Options exercisable December 31	4,874,970		$	16.24	6,218,074		$	13.89	6,251,294		$	12.61

Options outstanding at December 31, 2005 include 4,874,970 exercisable at that date and are summarized in the following table.

Options Outstanding									Options Exercisable
Range of Exercise Prices					Number Outstanding as of December 31, 2005	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Exercisable as of December 31, 2005	Weighted Average Exercise Price
$	6.59	to	$	9.89	37,334	3.3	$	7.58	37,334	$	7.58
$	9.90	to	$	13.19	422,234	4.2	$	10.06	422,234	$	10.06
$	13.20	to	$	16.48	1,887,177	5.0	$	15.67	1,887,177	$	15.67
$	16.49	to	$	19.78	2,667,366	6.1	$	17.50	2,431,915	$	17.46
$	19.79	to	$	23.07	9,350	3.4	$	20.58	9,350	$	20.58
$	23.08	to	$	26.37	22,568	2.3	$	23.45	22,568	$	23.45
$	26.38	to	$	29.67	22,424	4.4	$	28.08	22,424	$	28.08
$	29.68	to	$	32.96	41,968	1.4	$	30.20	41,968	$	30.20

Nonemployee Directors’ Stock Incentive Plans

The Company’s 1999 Nonemployee Directors’ Stock Incentive Plans provides for the granting of up to 1,200,000 shares of common stock in the form of stock option grants and restricted stock awards to nonemployee directors of the Company. The exercise price for each share is equal to market price of the common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant. At December 31, 2005, 160,904 options were outstanding at prices ranging from $6.59 to $29.67 per share, and 537,200 options had been exercised under this plan since the plan inception.

17. Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, as well as short-term loans, approximates fair value due to the short maturity of the instruments. The fair value of the available-for-sale securities is estimated based on quoted market prices for those investments.

The estimated fair value of long-term debt described in Note 12 at December 31, 2005 and 2004 was $816.8 million and $687.2 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.

The estimated fair value of liabilities for derivative instruments described in Note 3, excluding trading activities which are marked-to-market, was a $36.0 million asset and a $1.2 billion liability at December 31, 2005, and a $26.8 million asset and a $350.4 million liability at December 31, 2004.

18. Concentrations of Credit Risk

Revenues and related accounts receivable from the Equitable Supply segment’s operations are generated primarily from the sale of produced natural gas to certain marketers, Equitable Energy, LLC (an affiliate), other Appalachian Basin purchasers and utility and industrial customers located mainly in the Appalachian area; the sale of produced natural gas liquids to a gas processor in Kentucky; and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.

Equitable Utilities’ distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 274,400 residential, commercial and industrial customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. The Pipeline operations include FERC-regulated interstate pipeline transportation and storage service for the affiliated utility,

Equitable Gas Company (Equitable Gas), as well as other utility and end-user customers located in the northeastern United States. The unregulated marketing operations provide commodity procurement and delivery, physical natural gas management operations and control, and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.

Under previous state regulations, Equitable Gas was required to provide continuous natural gas service to residential customers during the winter heating season. The Responsible Utility Customer Protection Act (Act 201), which became effective in Pennsylvania on December 14, 2004, established new procedures for utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result of Act 201, the Company is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and complete customer terminations without approval from the PA PUC.

Approximately 69% and 67% of the Company’s accounts receivable balance as of December 31, 2005 and 2004, respectively, represent amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company’s criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2005 and 2004.

The Company is not aware of any significant credit risks that have not been recognized in provisions for doubtful accounts.

19. Commitments and Contingencies

The Company has annual commitments of approximately $31.4 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years as of December 31, 2005, which relate to natural gas distribution and production operations. However, the Company believes that approximately $20.0 million of these costs are recoverable in customer rates.

The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such

required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations. The Company has identified situations that require remedial action for which approximately $2.9 million is included in other credits in the Consolidated Balance Sheet as of December 31, 2005.

Operating lease rentals for office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $4.9 million in 2005, $4.2 million in 2004 and $4.1 million in 2003. Future lease payments under non-cancelable operating leases as of December 31, 2005 totaled $62.8 million (2006 - $7.3 million, 2007 - $6.5 million, 2008 - $5.8 million, 2009 - $4.3 million, 2010 - $3.6 million and thereafter - $35.3 million).

20. Guarantees

NORESCO Guarantees

In connection with its sale of the NORESCO domestic operations in December 2005, the Company agreed to maintain guarantees of certain of NORESCO’s obligations previously issued to the purchasers of NORESCO’s receivables. Under previously executed transactions to sell certain contractual receivables, NORESCO agreed to indemnify the purchasers of the receivables for future shortfalls that may arise from warranty and maintenance issues on the underlying customer contracts. Additionally, the Company agreed to issue additional guarantee obligations (including performance and payment bonds) after closing of the NORESCO sale in connection with certain receivable sales and customer contracts that were complete or nearly complete prior to the closing of the sale. The undiscounted maximum aggregate payments that may be due under the guarantees described above is approximately $248 million, and extends at a decreasing amount for approximately 20 years.

In addition, the Company agreed to maintain in place certain outstanding payment and performance bonds, letters of credit and other guarantee obligations supporting NORESCO’s obligations under certain customer contracts, existing leases and other items with an undiscounted maximum exposure to the Company of approximately $264 million, of which approximately $149 million relates to work already completed under the associated contracts. In addition, approximately $200 million of these guarantee obligations will end or be terminated not later than December 30, 2010.

In exchange for the Company’s agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee obligations, provided that the purchaser’s reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014.

The Company previously did not disclose the guarantee obligations described above because they were specifically exempt from disclosure under the provisions of FIN 45. In addition, the Company has determined that the likelihood it will be required to perform on these arrangements is remote and has not recorded any liabilities in its Consolidated Balance Sheet related to these guarantees.

Other Guarantees

In November 1995, Equitable, through a subsidiary, guaranteed a tax indemnification to the limited partners of ABP for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2005, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $46.0 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45, and has not been

modified subsequent to issuance. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that any potential loss from this guarantee is remote.

In June 2000, Equitable sold certain properties and, through a subsidiary, guaranteed a tax indemnification to the buyer for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. As of December 31, 2005, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $23.0 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that any potential loss from this guarantee is remote.

In December 2000, the Company entered into a transaction with ANGT by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. Appalachian NPI, LLC (ANPI) contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt. The Company provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company has received a market-based fee for providing the guarantee. As of December 31, 2005, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $43 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance.

21. Office Consolidation / Impairment Charges

In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations for total impairment charges of $7.8 million. These charges included a loss of $5.3 million, recorded in accordance with SFAS No. 146, on the early termination of operating leases for facilities deemed to have no economic benefit to the Company and a loss of $2.5 million, recorded in accordance with SFAS No. 144, on the impairment of assets.

22. Prepaid Forward Contract

In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver natural gas during the term of the contracts. The first contract was for five years; the second contract was for three years and was completed at the end of 2003. These contracts were recorded as prepaid forward sales and were recognized in income as deliveries occurred.

In June 2004, the Company amended the remaining prepaid natural gas contract, which was viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss of $5.5 million in other income, net in the Statement of Consolidated Income for the year ended December 31, 2004, reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue.

23. Other Items

In 2004, the Company settled a disputed property insurance coverage claim involving Kentucky West Virginia Gas Company, LLC, which is a part of the Equitable Supply operating segment. As a result of the settlement, the Company recognized income of approximately $6.1 million in 2004, which is included in other income, net, in the Statement of Consolidated Income for the year ended December 31, 2004.

In 2004, the Company renegotiated a processing agreement with one of its customers whereby the liquid processing agreement between the two parties was changed from a make-whole arrangement to a processing fee arrangement. As a result of this change, the Company recognized a net gain of $2.7 million, which is included in net operating revenues in the Statement of Consolidated Income for the year ended December 31, 2004.

24. Interim Financial Information (Unaudited)

The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company’s utility business and volatility of natural gas and oil commodity prices. The quarterly results have been reclassified to reflect the Company’s NORESCO business segment as discontinued operations for each period presented.

	March 31		June 30		September 30		December 31 (a)
	(Thousands, except per share amounts)
2005
Operating revenues	$	401,276	$	230,194	$	229,372	$	392,882
Net operating revenues	212,545		154,277		163,416		212,317
Operating income	127,196		53,459		54,689		108,468
Income from continuing operations before cumulative effect of accounting change	74,791		57,953		45,811		80,019
Income (loss) from discontinued operations, net of tax	1,615		6,366		680		(7,180		)
Net income	76,406		64,319		46,491		72,839
Earnings per share of common stock:
Income from continuing operations before cumulative effect of accounting change
Basic	$	0.62	$	0.48	$	0.37	$	0.67
Diluted	$	0.60	$	0.47	$	0.37	$	0.65
Income (loss) from discontinued operations, net of tax
Basic	$	0.01	$	0.05	$	0.01	$	(0.06	)
Diluted	$	0.01	$	0.05	$	0.01	$	(0.06	)
Net income
Basic	$	0.63	$	0.53	$	0.38	$	0.61
Diluted	$	0.61	$	0.52	$	0.38	$	0.59

	March 31		June 30			September 30		December 31
	(Thousands, except per share amounts)
2004
Operating revenues	$	366,501	$	204,940		$	168,481	$	305,261
Net operating revenues	193,010		137,320			133,647		169,156
Operating income	115,741		43,690			61,052		69,222
Income from continuing operations before cumulative effect of accounting change	68,647		155,225			34,667		40,251
Income (loss) from discontinued operations, net of tax	1,423		(24,398		)	1,016		3,023
Net income	70,070		130,827			35,683		43,274
Earnings per share of common stock:
Income from continuing operations before cumulative effect of accounting change
Basic	$	0.55	$	1.25		$	0.28	$	0.33
Diluted	$	0.54	$	1.22		$	0.27	$	0.33
Income (loss) from discontinued operations, net of tax
Basic	$	0.01	$	(0.20	)	$	0.01	$	0.02
Diluted	$	0.01	$	(0.19	)	$	0.01	$	0.02
Net income
Basic	$	0.56	$	1.05		$	0.29	$	0.35
Diluted	$	0.55	$	1.03		$	0.28	$	0.35

(a) Amounts for the quarter ended December 31, 2005, include an adjustment of $10.6 million to operating revenues in the Company’s Equitable Supply segment principally due to the Company’s conclusion that the well-head sales price allocated to a third party’s working interest gas in previous periods may have been lower than the Company was obligated to pay.

25. Natural Gas Producing Activities (Unaudited)

The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Supply segment in accordance with SFAS No. 69.

Production Costs

The following table presents the costs incurred relating to natural gas and oil production activities:

	2005		2004		2003
	(Thousands)
At December 31:
Capitalized costs	$	1,551,677	$	1,396,899	$	1,303,655
Accumulated depreciation and depletion	518,426		488,742		450,761
Net capitalized costs	$	1,033,251	$	908,157	$	852,894
Costs incurred:
Property acquisition:
Proved properties	$	57,500	$	—	$	—
Unproved properties	—		—		—
Land and leasehold maintenance	768		846		824
Development (a)	132,317		91,489		125,962

(a) Amounts include $72.0 million, $55.9 million and $82.7 million of costs incurred during 2005, 2004 and 2003, respectively, to develop the Company’s proved undeveloped reserves. The Company estimates that its future total development costs will be comprised of a similar percentage of costs incurred to develop the Company’s proved undeveloped reserves.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas and oil production:

	2005		2004		2003
	(Thousands)
Revenues:
Affiliated	$	11,856	$	10,599	$	11,457
Nonaffiliated	378,434		305,387		251,150
Production costs	61,483		43,274		35,687
Depreciation and depletion	49,281		41,275		35,974
Income tax expense	95,933		85,701		71,414
Results of operations from producing activities (excluding corporate overhead)	$	183,593	$	145,736	$	119,532

Reserve Information

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which was reviewed by the independent consulting firm of Ryder Scott Company L.P. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. All of the Company’s proved reserves are in the United States.

	2005		2004		2003
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	2,102,539		2,064,126		2,131,821
Revision of previous estimates	288,590		56,392		(41,053	)
Purchase of natural gas in place	19,159		—		—
Sale of natural gas in place	(57,700	)	—		(7,146	)
Extensions, discoveries and other additions (a)	84,717		54,247		49,926
Production	(78,105	)	(72,226	)	(69,422	)
End of year	2,359,200		2,102,539		2,064,126
Proved developed reserves:
Beginning of year	1,625,295		1,580,474		1,573,278
End of year	1,666,990		1,625,295		1,580,474

	2005		2004		2003
	(Thousands of Bbls)
Oil
Proved developed and undeveloped reserves:
Beginning of year	1,019		550		1,432
Revision of previous estimates	112		552		170
Purchase of oil in place	38		—		—
Sale of oil in place	(53	)	—		(969	)
Production	(108	)	(83	)	(83	)
End of year	1,008		1,019		550
Proved developed reserves:
Beginning of year	1,019		550		1,432
End of year	1,008		1,019		550

(a) Includes 29,995 MMcf, 17,246 MMcf and 31,755 MMcf of proved developed reserve extensions, discoveries and other additions during 2005, 2004 and 2003, respectively, which were not previously classified as proved undeveloped. The remaining balance represents additional proved undeveloped reserves.

Standard Measure of Discounted Future Cash Flow

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:

	2005			2004			2003
	(Thousands)
Future cash inflows	$	28,122,308		$	17,312,818		$	10,462,523
Future production costs	(3,939,210		)	(2,465,681		)	(1,938,827		)
Future development costs	(791,539		)	(409,141		)	(341,116		)
Future net cash flow before income taxes	23,391,559			14,437,996			8,182,580
10% annual discount for estimated timing of cash flows	(15,789,506		)	(9,736,734		)	(5,550,907		)
Discounted future net cash flows before income taxes	7,602,053			4,701,262			2,631,673
Future income tax expenses, discounted at 10% annually	(2,609,025		)	(1,740,878		)	(921,086		)
Standardized measure of discounted future net cash flows	$	4,993,028		$	2,960,384		$	1,710,587

Summary of changes in the standardized measure of discounted future net cash flows:

	2005			2004			2003
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(329,575	)	$	(273,558	)	$	(227,745	)
Net changes in prices, production and development costs	1,565,744			1,746,284			413,043
Extensions, discoveries and improved recovery, less related costs	272,419			121,051			63,645
Development costs incurred	76,694			68,688			70,112
Purchase of minerals in place – net	62,341			—			—
Sale of minerals in place – net	(129,466		)	—			(12,659		)
Revisions of previous quantity estimates	911,986			131,142			(111,228		)
Accretion of discount	457,225			263,166			221,873
Net change in income taxes	(868,147		)	(819,792		)	(140,101		)
Other	13,423			12,816			(16,753		)
Net increase	2,032,644			1,249,797			260,187
Beginning of year	2,960,384			1,710,587			1,450,400
End of year	$	4,993,028		$	2,960,384		$	1,710,587

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not Applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

The Principal Executive Officer and Principal Financial Officers conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officers concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report. There were no significant changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Equitable is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). Equitable’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

Equitable’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2005.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, has been audited by Ernst & Young, LLP, the independent registered public accounting firm that also audited the Company’s Consolidated Financial Statements. Ernst & Young’s attestation report on management’s assessment of the Company’s internal control over financial reporting appears in Part II, Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.

The Company has co-principal financial officers, Philip P. Conti, the Vice President and Chief Financial Officer, and David L. Porges, the Executive Vice President, Finance and Administration. Effective January 31, 2006, Mr. Conti assumed responsibility for the accounting and financial reporting functions, and continued his responsibility for the treasury, business development, planning and risk management functions. Mr. Conti reports to Mr. Porges, who has oversight responsibility for finance, human resources, legal, information technology, and environmental and safety compliance. Mr. Conti and Mr. Porges collaborate with respect to the Company’s financial reporting. Both co-principal financial officers assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 as described above and have made the certifications required by Rule 13a-14(a)/15d-14(a) and Section 1350 which are attached to this Form 10-K as Exhibits 31.2 and 31.3, and 32, respectively.

Item 9B. Other Information

Not Applicable.

PART III

Item 10. Directors and Executive Officers of the Registrant

The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 12, 2006, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2005:

• Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the section captioned “Item No. 1 - Election of Directors” in the Company’s definitive proxy statement;

• Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference from the section captioned “Stock Ownership and Performance – Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;

• Information required by Item 401 of Regulation S-K with respect to disclosure of audit committee financial expert is incorporated herein by reference from the section captioned “Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement; and

• Information required by Item 401 of Regulation S-K with respect to the identification of the members of the Audit Committee is incorporated by reference from the section captioned “Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement.

Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Form 10-K under the heading “Executive Officers of the Registrant (as of February 22, 2006),” and is incorporated herein by reference.

The Company has adopted a code of ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of ethics is posted on the Company’s website, http://www.eqt.com (under the “Corporate Governance” caption of the Investor Relations page) and a printed copy will be delivered to anyone who requests one by writing to the corporate secretary at Equitable Resources, Inc., c/o corporate secretary, 225 North Shore Drive, Pittsburgh, Pennsylvania 15212. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of ethics by posting such information on the Company’s website.

By certification dated April 26, 2005, the Company’s Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of NYSE corporate governance listing standards.

Item 11. Executive Compensation

Information required by Item 11 is incorporated herein by reference from the sections captioned “Executive Compensation,” “Employment and Other Arrangements” and “Directors’ Compensation and Retirement Program” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 12, 2006, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2005.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by Item 12 is incorporated herein by reference from the sections captioned “Stock Ownership and Performance” and “Equity Compensation Plans” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 12, 2006, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2005.

Item 13. Certain Relationships and Related Transactions

None.

Item 14. Principal Accounting Fees and Services

Information required by Item 14 is incorporated herein by reference from the section captioned “Item No. 2 — Ratification of Appointment of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement relating to the annual meeting of stockholders to be held on April 12, 2006, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2005.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	1.	Financial Statements
		The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.

	2.	Financial Statement Schedule
		The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K.

	3.	Exhibits
		The exhibits listed on the accompanying index to exhibits (pages 94 through 98) are filed as part of this Annual Report on Form 10-K.

EQUITABLE RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS COVERED

BY REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

Item 15 (a)

1. The following Consolidated Financial Statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8:

		Page Reference
Statements of Consolidated Income for each of the three years in the period ended December 31, 2005		46
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2005		47
Consolidated Balance Sheets as of December 31, 2005 and 2004		48
Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2005		50
Notes to Consolidated Financial Statements		51

2. Schedule for the Years Ended December 31, 2005, 2004 and 2003 included in Part IV:

II — Valuation and Qualifying Accounts and Reserves

All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE THREE YEARS ENDED DECEMBER 31, 2005

Column A	Column B		Column C				Column D		Column E
Description	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Additions Charged to Other Accounts (a)		Deductions (b)		Balance at End of Period
	(Thousands)
2005
Accumulated provisions for doubtful accounts	$	29,836	$	8,273	$	5,176	$	19,956	$	23,329
2004
Accumulated provisions for doubtful accounts	$	16,153	$	19,659	$	3,332	$	9,308	$	29,836
2003
Accumulated provisions for doubtful accounts	$	14,694	$	13,460	$	—	$	12,001	$	16,153

Note:

(a) Energy Assistance Program surcharge included in residential rates.

(b) Customer accounts written off, less recoveries.

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing
3.01	Restated Articles of Incorporation (amended through 7/18/05)	Filed as Exhibit 3.01 to Form 8-K filed on July 18, 2005
3.02	Bylaws of the Company (amended through January 12, 2005 and approved February 4, 2005)	Filed as Exhibit 3.01 to Form 8-K filed on February 10, 2005
4.01 (a)	Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank	Filed as Exhibit 4.1 to Registration Statement on From S-3 filed April 24, 1986 (Registration No. 2-80575)
4.01 (b)	Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank	Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1998
4.01 (c)	Supplemental Indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt	Filed as Exhibit 4.01 (f) to Form 10-K for the year ended December 31, 1996
4.01 (d)	Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes	Filed as Exhibit 4.01 (g) to Form 10-K for the year ended December 31, 1996
4.01 (e)	Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes	Filed as Exhibit 4.01 (h) to Form 10-K for the year ended December 31, 1997
4.01 (f)	Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes	Filed as Exhibit 4.01 (i) to Form 10-K for the year ended December 31, 1995
4.02 (a)	Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, a Trustee, dated as of July 1, 1996	Filed as Exhibit 4.01 (a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003
4.02 (b)	Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996	Filed as Exhibit 4.01 (j) to Form 10-K for the year ended December 31, 1996
4.02 (c)	Officer’s Declaration dated February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000	Filed as Exhibit 4.01 (c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003
4.02 (d)	Officer’s Declaration dated November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000	Filed as Exhibit 4.01 (c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing
4.02 (e)	Officer’s Declaration dated September 27, 2005 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of $150,000,000	Filed as Exhibit 4.01 (b) to Form S-4 Registration Statement (#333-104392) filed on October 28, 2005
4.03	Amended and Restated Rights Agreement dated as of January 23, 2004 between the Company and Mellon Investor Services, LLC, as Rights Agent, setting forth the amended and restated terms of the Company’s Preferred Stock Purchase Rights Plan	Filed as Exhibit 1 to Registration Statement on Form 8-A/A filed January 29, 2004
4.04 (a)	Revolving Credit Agreement dated as of August 11, 2005	Filed as Exhibit 4.01 to Form 10-Q for the quarter ended September 30, 2005
4.04(b)	First Amendment to Revolving Credit Agreement Dated as of December 14, 2005	Filed herewith as Exhibit 4.04(b)
* 10.01 (a)	1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated October 20, 2004)	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004
* 10.01 (b)	Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan	Filed as Exhibit 10.05 to Form 10-K for the year ended December 31, 2004
* 10.01 (c)	Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan	Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004
* 10.01 (d)	1994 Equitable Resources, Inc. Long-Term Incentive Plan	Filed as Exhibit 10.06 to Form 10-K for the year ended December 31, 1999
* 10.01 (e)	Equitable Resources, Inc. 2002 Executive Performance Incentive Program (as amended and restated May 1, 2003 and April 13, 2004)	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 20, 2004
* 10.01 (f)	Form of Participant Award Agreement under the Equitable Resources, Inc. 2002 Executive Performance Incentive Program	Filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004
* 10.01 (g)	Equitable Resources, Inc. 2003 Executive Performance Incentive Program (as amended and restated April 13, 2004)	Filed as Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2004
* 10.01 (h)	Form of Participant Award Agreement under the Equitable Resources, Inc. 2003 Executive Performance Incentive Program	Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2004
* 10.01 (i)	Equitable Resources, Inc. 2005 Executive Performance Incentive Program	Filed as Exhibit 10.01 to Form 8-K filed on March 1, 2005
* 10.01 (j)	Form of Participant Award Agreement under the Equitable Resources, Inc. 2005 Executive Performance Incentive Program	Filed as Exhibit 10.02 to Form 8-K filed on March 1, 2005

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing
* 10.02	Equitable Resources, Inc. Breakthrough Long-Term Incentive Plan with certain executives of the Company (as amended)	Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2000
* 10.03	1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan (as amended May 26, 1999)	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 1999
* 10.04	Equitable Resources, Inc. Executive Short-Term Incentive Plan	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2001
* 10.05	Equitable Resources, Inc. 2004 Short-Term Incentive Plan	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2004
* 10.06	Equitable Resources, Inc. 2005 Short-Term Incentive Plan	Filed as Exhibit 10.1 to Form 8-K filed on December 6, 2004
* 10.07	Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)	Filed as Exhibit 10.10 to Form 10-Q for the quarter ended June 30, 2003
* 10.08	Equitable Resources, Inc. 2005 Directors’ Deferred Compensation Plan (as amended and restated December 15, 2005)	Filed herewith as Exhibit 10.08
* 10.09	Equitable Resources, Inc. Employee Deferred Compensation Plan (amended and restated effective December 3, 2003)	Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 2003
* 10.10	Equitable Resources, Inc. 2005 Employee Deferred Compensation Plan	Filed as Exhibit 10.1 to Form 8-K filed on December 28, 2004
* 10.11 (a)	Employment Agreement dated as of May 4, 1998 with Murry S. Gerber	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 1998
* 10.11 (b)	Amendment No. 1 to Employment Agreement with Murry S. Gerber	Filed as Exhibit 10.09 (b) to Form 10-K for the year ended December 31, 1999
* 10.11 (c)	Amendment No. 2 to Employment Agreement with Murry S. Gerber	Filed as Exhibit 10.09 (c) to Form 10-Q for the quarter ended September 30, 2002
* 10.11 (d)	Amendment No. 3 to Employment Agreement with Murry S. Gerber	Filed as Exhibit 10.13 (d) to Form 10-K for the year ended December 31, 2003
* 10.11 (e)	Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Murry S. Gerber	Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2002
* 10.11 (f)	Supplemental Executive Retirement Agreement dated as of May 4, 1998 with Murry S. Gerber	Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 1998
* 10.11 (g)	Satisfaction Agreement In Respect of Supplemental Executive Retirement Agreement dated as of February 22, 2006 with Murry S. Gerber	Filed herewith as Exhibit 10.11(g)
* 10.11 (h)	Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with Murry S. Gerber	Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 1999
* 10.12 (a)	Employment Agreement dated as of July 1, 1998 with David L. Porges	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998
* 10.12 (b)	Amendment No. 1 to Employment Agreement with David L. Porges	Filed as Exhibit 10.13 (b) to Form 10-K for the year ended December 31, 1999
* 10.12 (c)	Amendment No. 2 to Employment Agreement with David L. Porges	Filed as Exhibit 10.13 (c) to Form 10-Q for the quarter ended September 30, 2002

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing
* 10.12 (d)	Amendment No. 3 to Employment Agreement with David L. Porges	Filed as Exhibit 10.14 (d) to Form 10-K for the year ended December 31, 2003
* 10.12 (e)	Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and David L. Porges	Filed as Exhibit 10.14 to Form 10-Q for the quarter ended September 30, 2002
* 10.12(f)	Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with David L. Porges	Filed as Exhibit 10.15 to Form 10-K for the year ended December 31, 1999
* 10.13 (a)	Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Philip P. Conti	Filed as Exhibit 10.26 to Form 10-Q for the quarter ended September 30, 2002
* 10.13 (b)	Non-Compete Agreement dated October 30, 2000 by and between Equitable Resources, Inc. and Philip P. Conti	Filed as Exhibit 10.27 (b) to Form 10-K for the year ended December 31, 2004
* 10.14(a)	Agreement dated May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996	Filed as Exhibit 10.14 (a) to Form 10-K for the year ended December 31, 1996
* 10.14 (b)	Agreement dated November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees	Filed as Exhibit 10.14 (b) to Form 10-K for the year ended December 31, 1996
* 10.14 (c)	Agreement dated November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees	Filed as Exhibit 10.14 (c) to Form 10-K for the year ended December 31, 1997
* 10.14 (d)	Agreement dated December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees	Filed as Exhibit 10.20 (d) to Form 10-K for the year ended December 31, 1998
* 10.15	Form of Indemnification Agreement between Equitable Resources, Inc. and all executive officers and outside directors	Filed as Exhibit 10.41 to Form 10-K for the year ended December 31, 2002
* 10.16	Directors’ Compensation and Retirement Program	Filed herewith as Exhibit 10.16
* 10.17 (a)	Change in Control Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and Randall L. Crawford	Filed as Exhibit 10.18(b) to Form 10-K for the year ended December 31, 2003
* 10.17 (b)	Non-Compete Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and Randall L. Crawford	Filed herewith as Exhibit 10.17 (b)
* 10.18 (a)	Change in Control Agreement dated October 23, 2000 by and between Equitable Resources, Inc. and Charlene J. Gambino (Petrelli)	Filed herewith as Exhibit 10.18 (a)
* 10.18 (b)	Non-Compete Agreement dated October 23, 2000 by and between Equitable Resources, Inc. and Charlene J. Gambino (Petrelli)	Filed herewith as Exhibit 10.18 (b)
* 10.19 (a)	Change in Control Agreement dated November 6, 2004 by and between Equitable Resources, Inc. and Diane L. Prier	Filed herewith as Exhibit 10.19 (a)
* 10.19 (b)	Non-Compete Agreement dated November 6, 2004 by and between Equitable Resources, Inc. and Diane L. Prier	Filed herewith as Exhibit 10.19 (b)

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing
21	Schedule of Subsidiaries	Filed herewith as Exhibit 21
23.01	Consent of Independent Registered Public Accounting Firm	Filed herewith as Exhibit 23.01
23.02	Consent of Independent Petroleum Engineers	Filed herewith as Exhibit 23.02
31.1	Rule 13(a)-14(a) Certification of Principal Executive Officer	Filed herewith as Exhibit 31.1
31.2	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer	Filed herewith as Exhibit 31.2
31.3	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer	Filed herewith as Exhibit 31.3
32	Section 1350 Certification of Principal Executive Officer and Co-Principal Financial Officers	Filed herewith as Exhibit 32

The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		EQUITABLE RESOURCES, INC.

	By:	/s/ MURRY S. GERBER
		Murry S. Gerber
		Chairman, President and Chief Executive Officer
		February 22, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


/s/ MURRY S. GERBER	Chairman, President and	February 22, 2006
Murry S. Gerber	Chief Executive Officer
(Principal Executive Officer)

/s/ DAVID L. PORGES	Vice Chairman and Executive	February 22, 2006
David L. Porges	Vice President, Finance and
(Co-Principal Financial Officer)	Administration

/s/ PHILIP P. CONTI	Vice President and	February 22, 2006
Philip P. Conti	Chief Financial Officer
(Co-Principal Financial Officer)

/s/ JOHN A. BERGONZI	Vice President and	February 22, 2006
John A. Bergonzi	Corporate Controller
(Principal Accounting Officer)

/s/ VICKY A. BAILEY	Director	February 22, 2006
Vicky A. Bailey

/s/ PHYLLIS A. DOMM	Director	February 22, 2006
Phyllis A. Domm

/s/ BARBARA S. JEREMIAH	Director	February 22, 2006
Barbara S. Jeremiah

/s/ THOMAS A. MCCONOMY	Director	February 22, 2006
Thomas A. McConomy

/s/ GEORGE L. MILES, JR.	Director	February 22, 2006
George L. Miles, Jr.

/s/ JAMES E. ROHR	Director	February 22, 2006
James E. Rohr

/s/ DAVID S. SHAPIRA	Director	February 22, 2006
David S. Shapira

/s/ LEE T. TODD, JR.	Director	February 22, 2006
Lee T. Todd, Jr.

/s/ JAMES W. WHALEN	Director	February 22, 2006
James W. Whalen

Washington, D.C. 20549

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

PENNSYLVANIA

25-0464690

225 North Shore Drive

DOCUMENTS INCORPORATED BY REFERENCE

PART I

PART II

PART III

PART IV

Forward-Looking Statements

Item 1A. Risk Factors

Item 3. Legal Proceedings

Item 4. Submission of Matters to a Vote of Security Holders

Investment Securities

Critical Accounting Policies Involving Significant Estimates

Net Fair Value of Third Party Contract (Liabilities) Assets at Period-End