Form 10-Q

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10-Q 1 d409093d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

¨	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: 1-16735

PVR PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

23-3087517

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

FIVE RADNOR CORPORATE CENTER, SUITE 500

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 975-8200

(Registrant’s telephone number, including area code)

PENN VIRGINIA RESOURCE PARTNERS, L.P

(Former name, former address and former fiscal year, if changed since last report)

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 (“Exchange Act”) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by a check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

As of October 16, 2012, 88,154,714 common units, 21,840,014 Class B Units, and 10,346,257 Special Units representing limited partner interests were outstanding.


		Page

PART I. Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		1

	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2012 and 2011		1

	Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011		2

	Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2012 and 2011		3

	Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 2012 and 2011		4

	Notes to Consolidated Financial Statements		5

	Forward-Looking Statements		17

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		32

Item 4.	Controls and Procedures		34

PART II. Other Information

Item 1.	Legal Proceedings		34

Item 1A.	Risk Factors		35

Item 6.	Exhibits		35

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues
Natural gas	$	78,026		$	120,240		$	215,780		$	324,447
Natural gas liquids		96,237			129,389			316,161			374,279
Gathering and transportation		27,229			10,081			62,488			24,172
Coal royalties		28,760			40,977			91,150			124,546
Gain on sale of plant		31,292			—			31,292			—
Other		7,303			7,665			21,305			24,757

Total revenues		268,847			308,352			738,176			872,201


Expenses
Cost of gas purchased		147,246			223,762			453,543			613,295
Operating		17,587			15,797			47,530			43,112
General and administrative		11,531			8,755			34,574			31,700
Acquisition related costs		—			—			14,049			—
Impairments		—			—			124,845			—
Depreciation, depletion and amortization		31,992			22,463			84,301			65,357

Total expenses		208,356			270,777			758,842			753,464


Operating income (loss)		60,491			37,575			(20,666	)		118,737

Other income (expense)
Interest expense		(20,288	)		(10,528	)		(45,616	)		(33,806	)
Derivatives		(1,524	)		8,690			2,201			(6,289	)
Other		104			120			329			384

Net income (loss)		38,783			35,857			(63,752	)		79,026

Noncontrolling interest net loss		—			—			—			664

Net income (loss) attributable to PVR Partners, L.P.	$	38,783		$	35,857		$	(63,752	)	$	79,690


Earnings (loss) per common unit, basic and diluted	$	0.16		$	0.50		$	(1.14	)	$	1.26

Weighted average number of common units outstanding, basic and diluted		88,366			71,197			83,834			63,019

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – unaudited

(in thousands)


	Three Months Ended September 30,					Nine Months Ended September 30
	2012			2011		2012			2011

Net income (loss)	$	38,783		$	35,857	$	(63,752	)	$	79,026
Reclassification adjustment for derivative activities		(201	)		42		(523	)		366

Comprehensive income (loss)	$	38,582		$	35,899	$	(64,275	)	$	79,392

The accompanying notes are an integral part of these Consolidated Financial Statements.

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	September 30, 2012			December 31, 2011
	September 30, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents	$	10,127		$	8,640
Accounts receivable, net of allowance for doubtful accounts		97,443			101,340
Other current assets		5,314			5,640

Total current assets		112,884			115,620


Property, plant and equipment		2,277,019			1,689,256
Accumulated depreciation, depletion and amortization		(455,009	)		(406,959	)

Net property, plant and equipment		1,822,010			1,282,297


Equity investments		96,685			81,162
Goodwill		70,283			—
Intangible assets (net of accumulated amortization of $33,782 and $38,587)		628,270			70,665
Other long-term assets		58,902			44,248


Total assets	$	2,789,034		$	1,593,992


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	152,754		$	124,082
Deferred income		3,963			3,416
Derivative liabilities		1,787			12,042

Total current liabilities		158,504			139,540


Deferred income		13,307			10,492
Other liabilities		20,626			21,256
Senior notes		900,000			300,000
Revolving credit facility		535,000			541,000
Partners’ capital
Common units		558,517			580,961
Class B units		407,814			—
Special units		195,046			—
Accumulated other comprehensive income		220			743

Total partners’ capital		1,161,597			581,704


Total liabilities and partners’ capital	$	2,789,034		$	1,593,992

The accompanying notes are an integral part of these Consolidated Financial Statements.

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011

Cash flows from operating activities
Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on sale of plant		(31,292	)		—			(31,292	)		—
Depreciation, depletion and amortization		31,992			22,463			84,301			65,357
Impairments		—			—			124,845			—
Derivative Contracts:					—
Total derivative losses (gains)		1,524			(8,690	)		(2,201	)		6,289
Cash payments to settle derivatives		(1,332	)		(6,699	)		(8,578	)		(19,477	)
Non-cash interest expense		1,589			1,040			4,217			4,735
Non-cash unit-based compensation		1,086			966			4,643			2,805
Equity earnings, net of distributions received		697			2,818			142			4,635
Other		(231	)		(127	)		(929	)		(909	)
Changes in operating assets and liabilities					—
Accounts receivable		(9,890	)		(2,766	)		3,908			(18,729	)
Accounts payable and accrued liabilities		31,594			5,345			16,581			20,335
Deferred income		1,840			(855	)		3,362			(730	)
Other assets and liabilities		(210	)		605			(455	)		(1,029	)

Net cash provided by operating activities		66,150			49,957			134,792			142,308


Cash flows from investing activities
Acquisitions		787			(95	)		(850,156	)		(122,135	)
Additions to property, plant and equipment		(173,455	)		(67,000	)		(348,449	)		(141,796	)
Proceeds from sale of plant		62,271			—			62,271			—
Other		(9,932	)		347			(20,992	)		2,558

Net cash used in investing activities		(120,329	)		(66,748	)		(1,157,326	)		(261,373	)


Cash flows from financing activities
Distributions to partners		(46,833	)		(34,887	)		(128,516	)		(99,696	)
Net proceeds (issuance costs) from equity offering		(219	)		—			577,743			—
Proceeds from issuance of senior notes		—			—			600,000			—
Proceeds from borrowings		108,000			60,000			359,000			252,000
Repayments of borrowings		(5,000	)		(5,000	)		(365,000	)		(25,000	)
Cash paid for debt issuance costs		(617	)		—			(19,206	)		(3,675	)
Cash paid for merger		—			(16	)		—			(6,620	)

Net cash provided by financing activities		55,331			20,097			1,024,021			117,009


Net increase (decrease) in cash and cash equivalents		1,152			3,306			1,487			(2,056	)
Cash and cash equivalents - beginning of period		8,975			10,602			8,640			15,964

Cash and cash equivalents - end of period	$	10,127		$	13,908		$	10,127		$	13,908


Supplemental disclosure:
Cash paid for interest	$	5,806		$	5,941		$	29,632		$	29,408

Noncash investing activities:
Other assets acquired related to acquisition	$	—		$	—		$	4,827		$	—
Other liabilities assumed related to acquisition	$	(430	)	$	—		$	33,499		$	2,084
Contribution of license agreement to joint venture	$	—		$	4,795		$	—		$	4,795
Special units issued as consideration of acquisition	$	—		$	—		$	191,302		$	—

The accompanying notes are an integral part of these Consolidated Financial Statements.

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL – unaudited (in thousands)


	Common Units					Class B Units				Special Units				Accumulated Other Comprehensive Income (loss)			Total

Balance at December 31, 2011		79,033	$	580,961			—	$	—		—	$	—	$	743		$	581,704

Unit-based compensation		113		3,648					—		—		—		—			3,648
Distributions paid		—		(128,516	)		461		—		—		—		—			(128,516	)
Issuance of units		9,009		177,743			21,379		400,000		10,346		191,302		—			769,045
Other				(9	)													(9	)
Net income (loss)		—		(75,310	)		—		7,814		—		3,744		—			(63,752	)
Other comprehensive income (loss)		—		—			—		—		—		—		(523	)		(523	)


Balance at September 30, 2012		88,155	$	558,517			21,840	$	407,814		10,346	$	195,046	$	220		$	1,161,597


	Common Units					Class B Units				Special Units				Accumulated Other Comprehensive Income (loss)		Noncontrolling interests of PVR			Total

Balance at December 31, 2010		38,293	$	213,646			—	$	—		—	$	—	$	159	$	220,845		$	434,650

Unit-based compensation		24		6,756			—		—		—		—		—		—			6,756
Costs associated with merger		—		(11,240	)		—		—		—		—		—		—			(11,240	)
Units issued to acquire non-controlling interests		32,665		204,537			—		—		—		—		250		(204,787	)		—
Distributions paid		—		(84,302	)		—		—		—		—		—		(15,394	)		(99,696	)
Net income (loss)		—		79,690			—		—		—		—		—		(664	)		79,026
Other comprehensive income (loss)		—		—			—		—		—		—		366		—			366


Balance at September 30, 2011		70,982	$	409,087			—	$	—		—	$	—	$	775	$	—		$	409,862

The accompanying notes are an integral part of these Consolidated Financial Statements.

PVR PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 2012

1.	Organization and Basis of Presentation

PVR Partners, L.P. is a publicly traded Delaware master limited partnership, and its limited partner common units representing limited partner interests are listed on the New York Stock Exchange (“NYSE”) under ticker symbol “PVR.” As used in these Notes to Consolidated Financial Statements, the “Partnership,” “PVR,” “we,” “us” or “our” mean PVR Partners, L.P. and, where the context requires, includes our subsidiaries.

We are principally engaged in the gathering and processing of natural gas and the management of coal and natural resource properties in the United States. We currently conduct operations in three business segments: (i) Eastern Midstream, (ii) Midcontinent Midstream and (iii) Coal and Natural Resource Management.

•

Eastern Midstream — Our Eastern Midstream segment is engaged in providing natural gas gathering, transportation and other related services in Pennsylvania and West Virginia. In addition, we own member interests in a joint venture that transports fresh water to natural gas producers.

•

Midcontinent Midstream — Our Midcontinent Midstream segment is engaged in providing natural gas gathering, processing, and other related services. In addition, we own member interests in joint ventures that gather and transport natural gas. These processing and gathering systems are located primarily in Oklahoma and Texas.

•

Coal and Natural Resource Management — Our Coal and Natural Resource Management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties.

In accordance with accounting standards, effective January 1, 2012, when reviewing long-lived assets to be held and used, including related tangible and intangible assets, we adopted the approach to review qualitative factors (such as, macroeconomic conditions, industry and market considerations, and overall financial performance) to determine whether it is more likely than not (that is, the likelihood of more than 50 percent) that the fair value of those assets is less than their carrying amount, including goodwill, if any. If we determine that it is more likely than not, we recognize an impairment loss if we determine that the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted using a rate commensurate with the risk and remaining life of the asset.

Effective January 1, 2012, we adopted the Accounting Standards Update (“ASU”) regarding the prominence of other comprehensive income in the financial statements. This ASU requires us to report comprehensive income in either a single statement or in two consecutive statements reporting net income and other comprehensive income. This amended presentation of comprehensive income does not change items that are reported in other comprehensive income or requirements to report reclassifications of items from other comprehensive income to net income. This ASU eliminates the option to report other comprehensive income and its components in the statement of changes in partners’ capital. We elected to present a second consecutive statement.

Our Consolidated Financial Statements include the accounts of PVR and all of our wholly-owned subsidiaries. Investments in non-controlled entities over which we exercise significant influence are accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation. Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Consolidated Financial Statements have been included.

Management has evaluated all activities of PVR through the date upon which our Consolidated Financial Statements were issued and concluded that while no subsequent events have occurred that would require recognition in the Consolidated Financial Statements or disclosure in these Notes.

All dollar and unit amounts presented in the tables to these Notes are in thousands unless otherwise indicated.

2.	Acquisition

The factors used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risk-adjusted basis, geographic location, quality of resources, and condition of assets.

Business Combination

Chief Acquisition

On May 17, 2012, we completed our purchase of the membership interests of Chief Gathering LLC (“Chief Gathering”) from Chief E&D Holdings LP, for a purchase price of approximately $1.0 billion (“Chief Acquisition”), payable in a combination of $849.3 million in cash and fair value of $191.3 million in a new class of limited partner interests in us (“Special Units”). The Special Units are substantially similar to our common units, except that we will not pay or accrue any distributions on them until they automatically convert to common units, on a one-for-one basis, on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013. The Special Units are subject to early conversion by us or a holder of Special Units in connection with certain events. See Note 9 for a description of the conversion rights and distribution rights applicable to the Special Units.

Chief Gathering owned and operated six natural gas gathering systems serving over 300,000 dedicated acres in the Marcellus Shale, located in the north central Pennsylvania counties of Lycoming, Bradford, Susquehanna, Sullivan, Wyoming and Greene and in Preston County, West Virginia. This transaction resulted in a major expansion of our pipeline systems in our Eastern Midstream segment.

We financed the cash portion of the purchase price for the Chief Acquisition through a combination of equity and debt. In May 2012, we received (i) $400 million in cash related to the sale of Class B Units to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P., representing a new class of limited partner interests in us, and (ii) $180 million in cash, related to the sale of common units to institutional investors in a private placement. We used the proceeds from the sale of the Class B Units and the common units to fund a portion of the cash purchase price for the Chief Acquisition. The remainder of the cash purchase price was funded by a portion of the $600 million of senior notes issued in a private placement in May 2012. See Note 9 for a description of the conversion rights and distribution rights applicable to the Class B Units.

The Chief Acquisition has been accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price has been allocated to the current assets and liabilities and the tangible, intangible and goodwill assets acquired. The purchase price allocation for the Chief Acquisition was finalized during the three months ended September 30, 2012. We completed certain post-closing adjustments with the seller and the appraisal of the assets acquired. Fair values have been developed using recognized business valuation techniques. Below is the detailed allocation of the preliminary purchase price allocation as of June 30, 2012 adjusted for final revisions:


	Preliminary Purchase Allocation			As of September 30, 2012 Purchase Accounting Adjustments			Revised Purchase Allocation

Cash consideration paid for Chief	$	850,049		$	(787	)	$	849,262
Special units issued as consideration to Chief		191,302			—			191,302

Total purchase price	$	1,041,351		$	(787	)	$	1,040,564


Accounts receivable	$	4,412					$	4,412
Property, plant and equipment		362,448			14,505			376,953
Intangible assets		637,000			(15,000	)		622,000
Goodwill		71,005			(722	)		70,283
Other long-term assets		415			—			415
Accounts payable		(33,929	)		430			(33,499	)

Total purchase price	$	1,041,351		$	(787	)	$	1,040,564

The intangible assets identified in the acquisition represent customer contracts and relationships, all of which are fully amortizable. Our estimate of the weighted-average amortization period is approximately 23 years.

The purchase price allocation includes approximately $70.3 million of goodwill. The significant factors that contributed to the recognition of goodwill included the positioning of PVR as the leading independent midstream service provider in the northeastern area of the Marcellus Shale, as the assets acquired from Chief Gathering complement our existing assets in the region. Goodwill recorded in connection with a business combination is not amortized, but is tested for impairment at least annually. Accordingly, the pro forma financial information below does not include amortization of goodwill recorded in the acquisition.

The following pro forma financial information reflects the consolidated results of our operations as if the Chief Acquisition and related financings had occurred on January 1, 2011. The pro forma information includes adjustments primarily for revenues, operating expenses, general and administrative expenses, depreciation of the acquired property and equipment, amortization of intangibles, interest expense for acquisition debt and the change in weighted average common units resulting from the issuance of common units. The pro forma financial information is not necessarily indicative of the results of operations had these transactions been effected on the assumed date (in thousands, except per unit data):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011

Revenues	$	268,847	$	312,844		$	751,719		$	886,454
Net income (loss) attributable to PVR	$	38,783	$	13,475		$	(76,376	)	$	20,257
Earnings (loss) per common unit, basic and diluted	$	0.15	$	(0.12	)	$	(1.55	)	$	(0.59	)

The acquisition related costs reported on the Consolidated Statement of Operations are costs related to the Chief Acquisition.

3.	Impairment

During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets in the Midcontinent Midstream segment located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). The gathering lines and customer contracts were written down to their fair value, which was determined using the income approach and discounting the estimated cash flows of the assets. This is a nonrecurring fair value measurement (see Footnote 5. Fair Value Measurements) that was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented a de minimis amount of our consolidated total revenues.

4.	Disposition

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized in Revenues on the face of the statement of operations.

5.	Fair Value Measurements

We present fair value measurements and disclosures applicable to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Fair value is an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. At September 30, 2012, the carrying values of all of these financial instruments, except the long-term debt with fixed interest rates, approximated fair value. The fair value of floating-rate debt approximates the carrying amount because the interest rates paid are based on short-term maturities. The fair value of our fixed-rate long-term debt is estimated based on the published market prices for the same or similar issues (a Level 1 category fair value measurement). As of September 30, 2012, the fair value of our fixed-rate debt was $930.8 million.

Recurring Fair Value Measurements

The following table summarizes the assets and liabilities measured at fair value on a recurring basis and includes our derivative financial instruments by categories for the periods presented:


				Fair Value Measurements at September 30, 2012, Using
Description	Fair Value Measurements at September 30, 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap liabilities - current	$	(422	)	$	—	$	(422	)	$	—
Commodity derivative liabilities - current		(1,365	)		—		(1,365	)		—

Total	$	(1,787	)	$	—	$	(1,787	)	$	—


				Fair Value Measurements at December 31, 2011, Using
Description	Fair Value Measurements at December 31, 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap liabilities - current	$	(1,433	)	$	—	$	(1,433	)	$	—
Commodity derivative liabilities - current		(10,609	)		—		(10,609	)		—

Total	$	(12,042	)	$	—	$	(12,042	)	$	—

We used the following methods and assumptions to estimate the fair values:

•

Commodity derivative instruments: We utilize collars and swap derivative contracts to hedge against the variability in the fractionation, or frac, spread. We determine the fair values of our commodity derivative agreements using discounted cash flows based on quoted forward prices for the respective commodities. Each is a Level 2 input. We use the income approach, using valuation techniques that convert future cash flows to a single discounted value.

•

Interest rate swaps: We have entered into interest rate swaps (“Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”). We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input.

Nonrecurring Fair Value Measurements

We completed the Chief Acquisition on May 17, 2012. See Note 2, “Acquisition,” for a description of this acquisition. In connection with our accounting for this acquisition, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions.

The following table summarizes the fair value estimates for nonfinancial assets and liabilities for the Chief Acquisition measured at fair value on a nonrecurring basis by category as of the acquisition date:


			Fair Value Measurements during 2012, Using
	Fair Value Measurements at Acquisition Date		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Description
Property, plant and equipment	$	376,953	$	—	$	—	$	376,953
Intangible assets	$	622,000	$	—	$	—	$	622,000
Goodwill	$	70,283	$	—	$	—	$	70,283
Other long-term assets	$	415	$	—	$	—	$	415

There are three methods of estimating the value of assets that comprise a business: (i) the income approach, (ii) the cost approach and (iii) the market approach. Our allocation of value to assets is discussed below.

Regarding the tangible assets, the cost approach was the primary method. Due to the fact that the assets were relatively new or had been recently constructed, the indirect method of the cost approach was viewed as the most accurate method for estimating the fair value of these tangible assets. Using the indirect method of the cost approach, the current reproduction cost of the tangible asset was estimated

by indexing the historical capitalized cost basis in the fixed asset records based on the asset type and historical acquisition date of each asset. These costs generally include the base cost of the tangible asset and any additional costs considerations relating to placing the asset in service. Due to the fact that these tangible assets have been in use over varying periods of time, allowances were made for physical, functional and economic factors affecting utility and value as applicable.

The intangible assets were valued using the income approach with the application of the discounted cash flow method. The principle behind this method was that the value of an intangible asset is equal to the present value of the incremental cash flows attributable only to the subject intangible asset after deducting contributory asset charges. These incremental cash flows are then discounted to their present value.

As part of consideration of the Chief Acquisition, we issued a new class of PVR limited partner interests to Chief E&D Holdings LP (“Special Units”) with a fair value of $191.3 million. For the purpose of estimating the fair value of the Special Units, our unit price on the acquisition date was used and adjusted for the nine quarters where we neither pay nor accrue distributions on these units. The value was further adjusted to reflect the lack of marketability. The Special Units automatically convert into common units on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013.

In connection with our review of tangible and related intangible assets, if there is an indication of impairment and the estimated undiscounted future cash flows do not exceed the carrying value of the tangible and intangible assets, then these assets are written down to their fair value. During the first quarter of 2012, the North Texas Gathering System was reviewed for impairment and found to be impaired. The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective gas gathering assets. Because these significant fair value inputs are typically not observable, we have categorized the amounts as Level 3 inputs. The assets of the North Texas Gathering System were written down to their fair value of $5.7 million which included intangible assets of zero.

6.	Derivative Instruments

Natural Gas Commodity Derivatives

We determine the fair values of our derivative agreements using third-party forward prices for the respective commodities as of the end of the reporting period and discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position. The following table sets forth our positions as of September 30, 2012 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:


	Average Volume Per Day		Swap Price		Weighted Average Price				Fair Value at September 30, 2012
	Average Volume Per Day		Swap Price		Put		Call		Fair Value at September 30, 2012

NGL - natural gasoline collar		(gallons)				(per gallon)
Fourth quarter 2012		54,000			$	1.75	$	2.02	$	(265	)

Crude oil swap		(barrels)		(per barrel)
Fourth quarter 2012		600	$	88.62						(225	)

Natural gas purchase swap		(MMBtu)		(MMBtu)
Fourth quarter 2012		4,000	$	5.195						(688	)

Settlements to be paid in subsequent period										(187	)

Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the positions of the Interest Rate Swaps as of September 30, 2012:


	Notional Amounts (in millions)		Swap Interest Rates (1)					Fair Value at September 30, 2012
Term	Notional Amounts (in millions)		Pay			Receive		Fair Value at September 30, 2012

October 2012 - December 2012	$	100.0		2.09	%		LIBOR	$	(422	)

(1)	References to LIBOR represent the 3-month rate.

We reported a (i) net derivative liability of $0.4 million at September 30, 2012 and (ii) gain in accumulated other comprehensive income (“AOCI”) of $0.2 million as of September 30, 2012 related to the Interest Rate Swaps. In connection with periodic settlements and related reclassification of other comprehensive income, we recognized $0.5 million of net hedging gains on the Interest Rate

Swaps in the derivatives line on the Consolidated Statements of Operations during the nine months ended September 30, 2012. See the following “Financial Statement Impact of Derivatives” section for the impact of the Interest Rate Swaps on our Consolidated Financial Statements.

Financial Statement Impact of Derivatives

The following table summarizes the effects of our derivative activities, as well as the location of gains (losses) on our Consolidated Statements of Operations for the periods presented:


	Location of gain (loss) on derivatives recognized in statement of operations	Three Months Ended September 30,						Nine Months Ended September 30,
		2012			2011			2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivatives	$	171		$	(58	)	$	322		$	(956	)
Commodity contracts	Derivatives		(1,695	)		8,748			1,879			(5,333	)


Total increase or decrease in operating income from net gain (loss) resulting from derivatives		$	(1,524	)	$	8,690		$	2,201		$	(6,289	)


Realized and unrealized derivative impact:
Cash paid for commodity and interest rate contract settlements	Derivatives	$	(1,332	)	$	(6,699	)	$	(8,578	)	$	(19,477	)
Unrealized derivative gains (losses)	Derivatives		(192	)		15,389			10,779			13,188


Total increase or decrease in operating income from net gain (loss) resulting from derivatives		$	(1,524	)	$	8,690		$	2,201		$	(6,289	)

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments on our Consolidated Balance Sheets for the periods presented:


		Fair Values as of September 30, 2012				Fair Values as of December 31, 2011
	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities - current	$	—	$	422	$	—	$	1,433
Commodity contracts	Derivative assets/liabilities - current		—		1,365		—		10,609

Total derivatives not designated as hedging instruments		$	—	$	1,787	$	—	$	12,042


Total fair value of derivative instruments		$	—	$	1,787	$	—	$	12,042

As of September 30, 2012, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of September 30, 2012, we did not own derivative instruments containing credit risk contingencies.

7.	Equity Investments

In accordance with the equity method of accounting, we recognized earnings from all equity investments in the aggregate of $3.8 million and $4.3 million for the nine months ended September 30, 2012 and 2011, with a corresponding increase in the investment. The joint ventures generally pay quarterly distributions on their cash flow. We received distributions of $4.0 million and $8.9 million for the nine months ended September 30, 2012 and 2011, with a corresponding decrease in the investment. Equity earnings related to our joint venture interests are recorded in other revenues on the Consolidated Statements of Operations. The equity investments for all joint ventures are included in the equity investments caption on the Consolidated Balance Sheets.

As mentioned in Note 4, “Dispositions,” as part of the Crossroads sale we sold our 50% ownership in Crosspoint, an approximately 11-mile gas pipeline. The earnings and distributions related to the time period prior to July 3, 2012 are included in the amounts noted above. Earnings for the nine months ended September 30, 2012 and 2011 were $0.3 million and $0.5 million related to Crosspoint. Distributions for the same periods were $0.5 million and $0.5 million from Crosspoint. The net equity investment amount sold as of July 3, 2012 was $6.2 million.

Financial statements from our investees are not sufficiently timely for us to apply the equity method currently. Therefore, we record our share of earnings or losses of an investee from the most recently available financial statements, which are usually on a one-month lag. This lag in reporting is consistent from period to period.

Summarized financial information of unconsolidated equity investments is as follows for the periods presented:


	August 31, 2012		November 30, 2011
Current assets	$	34,395	$	24,581
Noncurrent assets	$	240,388	$	217,518
Current liabilities	$	20,674	$	14,861
Noncurrent liabilities	$	4,136	$	2,571

	Nine Months Ended August 31,
	2012		2011
Revenues	$	42,772	$	43,659
Expenses	$	29,190	$	26,125
Net income	$	13,582	$	17,534

8.	Long-term Debt

Revolver

On April 23, 2012, our wholly-owned subsidiary, PVR Finco LLC, entered into the second amendment to our amended and restated secured credit facility (the “Revolver”) to allow for certain modifications to facilitate the Chief Acquisition. The second amendment modified the restrictive covenants in the Revolver to permit us to incur certain indebtedness prior to the consummation of the Chief Acquisition for the purpose of funding a portion of the purchase price of Chief Gathering, and modified the mandatory prepayment covenant in the Revolver to allow the proceeds from indebtedness incurred or equity issued in connection with the Chief Acquisition to be used to fund a portion of the purchase price of Chief Gathering. Additionally, several modifications to the Revolver became effective upon the closing of the Chief Acquisition. The Maximum Leverage Ratio covenant was modified to allow us to maintain a ratio of Consolidated Total Indebtedness (as defined in the Revolver amendment), as measured at the end of each fiscal quarter, to Consolidated EBITDA (as defined in the Revolver amendment), calculated as of the end of each fiscal quarter for the four quarters then ended, of not more than (i) 6.50 to 1.00 commencing with the fiscal period ended June 30, 2012 through the fiscal period ended December 31, 2012 and (ii) 5.25 to 1.00 for the fiscal period ending March 31, 2013 and each fiscal period thereafter. The Maximum Secured Leverage Ratio covenant was replaced by a Maximum Senior Secured Leverage Ratio covenant that requires us to maintain a ratio of Consolidated Senior Secured Indebtedness (as defined in the Revolver amendment), as measured at the end of each fiscal quarter, to Consolidated EBITDA, calculated as of each fiscal quarter for the four quarters then ended, of not more than 4.00 to 1.00.

Our Revolver allows for adjustments to Consolidated EBITDA for material capital projects which exceed $10.0 million. The adjustments to Consolidated EBITDA have certain limitations and are approved by PNC Bank, as administrative agent to the Revolver.

Further, on the effective date of the Chief Acquisition, the variable pricing contained in the Revolver was amended to create two new tiers of pricing that apply when our Leverage Ratio (as defined in the Revolver amendment) is greater than 5.00 to 1.00. The borrowings under the Revolver bear interest, at our option, at either a Base Rate (as defined in the Revolver amendment), plus an applicable margin, or a rate derived from the London Interbank Offered Rate (“LIBOR”) as adjusted for statutory reserve requirements, plus an applicable margin. In each case, upon the effective date of the Chief Acquisition, May 17, 2012, the applicable margin is determined by our Leverage Ratio and, in the case of Base Rate loans, will range from 0.75% to 2.50% and, in the case of LIBOR loans, from 1.75% to 3.50%. Commencing with the fiscal period ending March 31, 2013, the variable pricing reverts to the pricing in effect immediately prior to the effective date of the Chief Acquisition.

As of September 30, 2012, net of outstanding indebtedness of $535.0 million and letters of credit of $7.9 million, we had remaining borrowing capacity of $457.1 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2012 was approximately 3.3%. We do not have a public rating for the Revolver. As of September 30, 2012, we were in compliance with all covenants under the Revolver.

Bridge Loans

In April 2012, in connection with the proposed Chief Acquisition, we obtained a commitment from commercial banks for senior unsecured bridge loans in an aggregate amount up to $220 million (the “Bridge Loans”). The commitment was to expire upon the earliest to occur of the termination date as defined in the Chief purchase agreement, the consummation of the Chief Acquisition without the use of the Bridge Loans or August 9, 2012. In May 2012, we terminated the Bridge Loans upon issuance of the 8.375% Senior Notes.

Senior Notes

On May 17, 2012, we completed the issuance of $600 million of senior notes in a private placement. These notes were priced at 100% of the principal amount and bear interest at a rate of 8.375% per year, due September 1, 2020. They are fully and

unconditionally guaranteed by our existing and future domestic restricted subsidiaries, subject to certain exceptions. Approximately $250 million of the proceeds from the senior notes offering was used in connection with the financing of the Chief Acquisition, and the remainder was used to pay down a portion of the outstanding borrowings under our Revolver. These senior notes were incremental to our existing $300 million of senior notes already outstanding.

9.	Partners’ Capital and Distributions

As of September 30, 2012, partners’ capital consisted of 88.2 million common units, 10.3 million Special Units and 21.8 million Class B Units.

Common Units

In connection with the Chief Acquisition, we sold common units to institutional investors in a private placement in the amount of $177.7 million, net of offering costs.

Special Units

In connection with the closing of the Chief Acquisition, on May 17, 2012, we issued a new class of PVR limited partner interests to Chief E&D Holdings LP with a fair value of $191.3 million (the “Special Units”). The Special Units are substantially similar to our common units, except that the Special Units will neither pay nor accrue distributions for six consecutive quarters commencing after the closing of the Chief Acquisition. The Special Units will automatically convert into common units on a one-for-one basis on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013. The Special Units are subject to early conversion by us or a holder of Special Units in connection with certain events, including a sale of all or substantially all of our assets to any third party or a transaction that results in any party, other than the holders of our common units immediately prior to such transaction, acquiring a majority of our common units or other securities of the surviving entity or any voting securities that are not subject to the voting limitations applicable to our common units under our limited partnership agreement or similar restrictions.

On November 14, 2012, the date on which we will pay distributions with respect to the quarter ended September 30, 2012, there will be 10,346,257 Special Units outstanding. Absent an early conversion event, the Special Units will not be entitled to accrue distributions until the quarter commencing on October 1, 2013. If the Special Units would have been entitled to accrue and receive the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended September 30, 2012, we would have paid an aggregate of $5.6 million in distributions to the holders of the Special Units.

Class B Units

In connection with the closing of the Chief Acquisition, on May 17, 2012, we issued a new class of PVR limited partner interests to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. for $400.0 million (the “Class B Units”). The Class B Units will share equally with our common units with respect to the payment of distributions but, until they convert into common units, such distribution (the “Class B Distribution Amount”) will be paid in additional Class B Units unless we elect to pay the distributions on the Class B Units in cash (the “Class B Unit Distribution”).

The number of additional Class B Units to be issued in connection with a distribution with respect to the Class B Units shall be the quotient of (A) the Class B Distribution Amount divided by (B) the volume-weighted average trading price per unit, as adjusted for splits, combinations and other similar transactions, of our common units, calculated over the consecutive 30-trading day period ending on the close of trading on the trading day immediately prior to such date, calculated as of the date the Class B Unit Distribution is declared; provided that instead of issuing any fractional Class B Units, we will round the number of Class B Units issued down to the next lower whole Class B Unit and pay cash in lieu of such fractional units, or at our option, we may round the number of Class B Units issued up to the next higher whole Class B Unit. In the event of a liquidation, unit exchange, merger, consolidation or similar event, each Class B Unit (prior to its eligibility for conversion as described below) will be entitled to receive the greater of (1) the amount of cash or property distributed in respect of each common unit and (2) an amount of cash or property having a value equal to $18.91 per unit (the “Class B Unit Price”).

The Class B Units may be converted into Common Units on a one-for-one basis at the option of the holder in the following amounts and subject to the following conditions: (1) 50% of the outstanding Class B Units may be converted after January 1, 2014, provided that the volume-weighted average price of our common units for the 30 trading days (the “30-day VWAP”) preceding any date during the quarter ending December 31, 2013 exceeds $30 per common unit; (2) 50% of the outstanding Class B Units may be converted after April 1, 2014, provided that the 30-day VWAP exceeds $30 per common unit on any day during the quarter ending March 31, 2014; and (3) amounts of Class B Units having a minimum value of $50.0 million calculated using the 30-day VWAP preceding the date of calculation at any time on or after July 1, 2014. In addition, we may elect to convert all (but not less than all) outstanding Class B Units into common units on a one-for-one basis at any time on or after July 1, 2014. The number of Class B Units is subject to adjustment for issuances below the Class B Unit Price prior to conversion on a weighted average basis, unit splits and unit combinations.

On November 14, 2012, the date on which we will pay distributions with respect to the quarter ended September 30, 2012, there will be 21,840,014 Class B Units outstanding. We will pay distributions to the holders of the Class B Units with respect to the quarter ended September 30, 2012 by issuing an aggregate of 465,774 additional Class B Units. If we were to pay distributions to the holders of the Class B Units in cash, rather than in additional Class B Units, at the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended September 30, 2012, the amount of cash distributions that would be attributable to the Class B Units would be an aggregate of $11.8 million.

Net Income (Loss) per Common Unit

The following table reconciles net income (loss) and weighted average common units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit data):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011

Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026
Noncontrolling interest net loss		—			—			—			664

Net income (loss) attributable to PVR Partners, L.P.	$	38,783		$	35,857		$	(63,752	)	$	79,690
Less:
Distributions to participating securities		(11,814	)		(111	)		(17,534	)		(300	)
Recognition of beneficial conversion feature (1)		(17,120	)		—			(28,174	)		—
Participating securities’ allocable share of undistributed net loss (income)		3,969			(111	)		14,109			(256	)

Net income (loss) allocable to common units, basic	$	13,818		$	35,635		$	(95,351	)	$	79,134

Participating securities’ allocable share of undistributed net income (loss)		—			111			—			256
Reallocation of participating securities’ share of undistributed net income (loss)		—			(111	)		—			(256	)

Net income (loss) allocable to common units, diluted	$	13,818		$	35,635		$	(95,351	)	$	79,134


Weighted average number of common units outstanding, basic and diluted		88,366			71,197			83,834			63,019

Net income (loss) per common unit, basic and diluted	$	0.16		$	0.50		$	(1.14	)	$	1.26

(1)

Special Units and Class B Units were issued at prices below the market price of the common units into which they are convertible. The aggregate discount of $138.1 million represents a beneficial conversion feature which is considered a non-cash distribution that will be distributed ratably using the effective yield method over the period the Special Units and Class B Units are outstanding. The impact of the beneficial conversion feature is included as distributed income to Class B Units and Special Units with a corresponding reduction in net income allocable to common units in the calculation of net income (loss) per common unit for the three and nine months ended September 30, 2012.

Basic net income (loss) per common unit is computed by dividing net income (loss) allocable to common units by the weighted average number of common units outstanding and vested deferred common units outstanding during the period. Diluted net income (loss) per common unit is computed by dividing net income (loss) allocable to common units by the weighted average number of common units outstanding and vested deferred common units outstanding during the period and, when dilutive, Class B Units, Special Units, and phantom units. The following table presents the weighted average number of each class of participating securities that were excluded from the diluted net income (loss) per common unit calculation because the inclusion of these units would have had an antidilutive effect:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011

Special units		10,346		—		5,173		—
Class B units		21,620		—		10,770		—
Phantom units		73		39		51		24

		32,039		39		15,994		24

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to common unitholders of record. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or any other agreements and (iii) provide funds for distributions to unitholders for any one or more of the next

four quarters. During the three and nine months ended September 30, 2012, we paid cash distributions of $46.8 million and $128.5 million. During the three and nine months ended September 30, 2011, we paid cash distributions of $34.9 million and $99.7 million.

On November 14, 2012, we will pay a $0.54 per unit quarterly distribution to common unitholders of record on November 7, 2012.

10.

Unit-Based Compensation

The PVR GP, LLC Sixth Amended and Restated Long-Term Incentive Plan (the “LTIP”) permits the grant of common units, deferred common units, unit options, restricted units and phantom units to employees and directors of our general partner and its affiliates. Common units and deferred common units granted under the LTIP are immediately vested, and we recognize compensation expenses related to those grants on the grant date. Restricted units and the time-based and performance-based phantom units granted under the LTIP generally vest over a three-year period, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period. Compensation expense related to these grants is recorded in the general and administrative expenses caption on our Consolidated Statements of Operations. During the nine months ended September 30, 2012, we granted 238 thousand phantom units at a weighted average grant-date fair value of $24.13 per unit, consisting of 125 thousand time-based phantom units and 113 thousand performance-based units.

Time-based phantom units vest over a three-year period, with one-third vesting in each year. Some of the time-based phantom units vested during the nine months ended September 30, 2012. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units. The fair value of time-based phantom units is calculated based on the grant-date unit price. Time-based phantom units are entitled to non-forfeitable distribution rights which are paid quarterly along with the common unit distributions.

Performance-based phantom units cliff-vest at the end of a three year period. The number of units that vest could range from 0% to 200% and depends on the outcome of unit market performance compared to peers and key results of operations metrics. Performance-based phantom units are entitled to forfeitable distribution equivalent rights which accumulate over the term of the units and will be paid in cash to the grantees at the date of vesting. The fair value of each performance-based phantom unit granted during 2012 was estimated on the date of grant as $23.34 using a Monte Carlo simulation approach that uses the assumptions noted in the following table. Expected volatilities are based on historical changes in the market value of our common units. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the phantom units, continuously compounded:


	2012
Expected volatility		34.03	%
Expected life		2.9 years
Risk-free interest rate		0.40	%

In connection with the normal three-year vesting of phantom units, as well as common unit and deferred common unit awards, we recognized the following expense during the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Phantom units	$	939	$	826		4,196		2,186
Director deferred and common units		147		140		447		619

	$	1,086	$	966	$	4,643	$	2,805

11.

Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material adverse effect on our financial position or results of operations.

On July 24, 2012, the Pennsylvania Department of Environmental Protection (PA DEP) presented the Partnership’s subsidiary, PVR Marcellus Gas Gathering, LLC, with a proposed Consent Assessment of Civil Penalty totaling approximately $0.2 million in connection with alleged erosion and sediment control violations incurred during construction of its pipelines and related facilities in Lycoming County, Pennsylvania. The Partnership is in discussions with the PA DEP regarding the proposed penalty. The timing or outcome of these discussions cannot be reasonably determined at this time.

Environmental Compliance

As of September 30, 2012 and December 31, 2011, our environmental liabilities were $0.7 million and $0.8 million, which represent our best estimate of the liabilities as of those dates related to our Coal and Natural Resource Management, Eastern Midstream and Midcontinent Midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. At September 30, 2012 approximately 73%, or $71.0 million, of our consolidated accounts receivable resulted from our Midcontinent Midstream segment, approximately 14%, or $13.6 million, resulted from our Eastern Midstream segment, and approximately 13%, or $12.8 million, resulted from our Coal and Natural Resource Management segment. There were two significant customers in the Midcontinent Midstream segment, which accounted for 22%, or $21.9 million, of the consolidated accounts receivable at September 30, 2012. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these natural gas midstream customers. For the nine months ended September 30, 2012, 32% of our Midcontinent Midstream segment’s revenues and 25% of our total consolidated revenues were from these two natural gas midstream customers.

12.

Segment Information

Our reportable segments are as follows:

•


	Eastern Midstream		Midcontinent Midstream			Coal and Natural Resource Management		Consolidated
For the three months ended September 30, 2012
Revenues	$	26,800	$	207,522		$	34,525	$	268,847
Cost of midstream gas purchased		—		147,246			—		147,246
Operating costs and expenses		5,360		15,990			7,768		29,118
Depreciation, depletion & amortization		11,867		11,913			8,212		31,992

Operating income	$	9,573	$	32,373		$	18,545	$	60,491

Interest expense									(20,288	)
Derivatives									(1,524	)
Other									104

Net income								$	38,783

Additions to property and equipment	$	146,726	$	25,919		$	23	$	172,668

For the three months ended September 30, 2011
Revenues	$	7,720	$	253,176		$	47,456	$	308,352
Cost of midstream gas purchased		—		223,762			—		223,762
Operating costs and expenses		1,137		15,362			8,053		24,552
Depreciation, depletion & amortization		987		11,904			9,572		22,463

Operating income	$	5,596	$	2,148		$	29,831	$	37,575

Interest expense									(10,528	)
Derivatives									8,690
Other									120

Net income								$	35,857

Additions to property and equipment	$	32,126	$	34,779		$	190	$	67,095

For the nine months ended September 30, 2012
Revenues	$	59,397	$	571,053		$	107,726	$	738,176
Cost of midstream gas purchased		—		453,543			—		453,543
Operating costs and expenses		10,337		48,217			23,550		82,104
Acquisition related costs		14,049		—			—		14,049
Impairments		—		124,845			—		124,845
Depreciation, depletion & amortization		22,322		37,220			24,759		84,301

Operating income	$	12,689	$	(92,772	)	$	59,417	$	(20,666	)

Interest expense									(45,616	)
Derivatives									2,201
Other									329

Net income								$	(63,752	)

Additions to property and equipment	$	1,095,723	$	101,894		$	988	$	1,198,605

For the nine months ended September 30, 2011
Revenues	$	16,582	$	711,190		$	144,429	$	872,201
Cost of midstream gas purchased		—		613,295			—		613,295
Operating costs and expenses		2,035		46,811			25,966		74,812
Depreciation, depletion & amortization		2,151		35,228			27,978		65,357

Operating income	$	12,396	$	15,856		$	90,485	$	118,737

Interest expense									(33,806	)
Derivatives									(6,289	)
Other									384

Net income								$	79,026

Additions to property and equipment	$	75,153	$	77,880		$	110,898	$	263,931


	Total assets at
	September 30, 2012		December 31, 2011

Eastern Midstream	$	1,472,283	$	174,442
Midcontinent Midstream		628,172		736,354
Coal and Natural Resource Management		688,579		683,196

Totals	$	2,789,034	$	1,593,992

Forward-Looking Statements

Certain statements contained in this Quarterly Report on Form 10-Q include “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical fact, are forward-looking statements. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

the volatility of commodity prices for natural gas, natural gas liquids, or NGLs and coal;

•

our ability to access external sources of capital;

•

any impairment write-downs of our assets;

•

the relationship between natural gas, NGL and coal prices;

•

the projected demand for and supply of natural gas, NGLs and coal;

•

competition among natural gas midstream companies and among producers in the coal industry generally;

•

our ability to acquire natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms or new coal reserves;

•

our ability to retain existing or acquire new natural gas midstream customers and coal lessees

•

the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;

•

our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our unitholders;

•

the experience and financial condition of our natural gas midstream and coal lessees customers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;

•

operating risks, including unanticipated geological problems, incidental to our Natural Resource Management or Eastern Midstream and Midcontinent Midstream and Coal businesses;

•

our ability to successfully complete the development of Chief Gathering LLC’s midstream systems, integrate the business of Chief Gathering LLC with ours and realize the anticipated benefits from the acquisition of Chief Gathering LLC;

•

the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production;

•

the occurrence of unusual weather or operating conditions including force majeure events;

•

delays in anticipated start-up dates of new processing plants in our Eastern Midstream and Midcontinent Midstream businesses and our lessees’ mining operations and related coal infrastructure projects;

•

environmental risks affecting the production, gathering and processing of natural gas or the mining of coal reserves;

•

the timing of receipt of necessary governmental permits by us or our lessees;

•

hedging results;

•

accidents;

•

changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators and permissible levels of mining runoff;

•

uncertainties relating to the effects of regulatory guidance on permitting under the Clean Water Act and the outcome of current and future litigation regarding mine permitting;

•

risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions;

•

other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2011. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 2

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of PVR Partners, L.P. and its subsidiaries (the “Partnership,” “PVR,” “we,” “us” or “our”) should be read in conjunction with our Consolidated Financial Statements and Notes thereto in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership that is principally engaged in the gathering and processing of natural gas and the management of coal and natural resource properties in the United States.

In connection with our recent acquisition described below we now manage our business in three operating segments: (i) Eastern Midstream, (ii) Midcontinent Midstream and (iii) Coal and Natural Resource Management.

•

Key Developments

During the nine months ended September 30, 2012, the following general business developments and corporate actions had an impact, or will have an impact, on our results of operations. A discussion of these key developments follows:

Wyoming Pipeline

On September 30, 2012, we completed construction and began commercial operation of a 30-mile long, 24 inch diameter natural gas trunkline serving Marcellus Shale producers in Pennsylvania. The pipeline has a capacity of 750 million cubic feet per day and extends from northern Wyoming County southward to a new interconnection in Luzerne County with Transco’s interstate pipeline system. We have fee based agreements with five producers for transportation service on the pipeline.

Chief Acquisition

On May 17, 2012, we purchased the membership interests of Chief Gathering LLC (“Chief Gathering”) from Chief E&D Holdings LP, for a purchase price of approximately $1.0 billion (“Chief Acquisition”), payable in a combination of $849.3 million in cash and fair value of $191.3 million in a new class of limited partner interests in us (“Special Units”). The Special Units are substantially similar to our common units except that we will neither pay nor accrue distributions on the Special Units for six consecutive quarters following their issuance. The Special Units automatically convert to common units on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013.

We financed the cash portion of the purchase price for the Chief Acquisition through a combination of equity and debt. In May 2012, we received (i) $400 million in cash related to the sale of Class B Units to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P., representing a new class of limited partner interests in us, and (ii) $180 million in cash related to the sale of common units to institutional investors in a private placement. We used the proceeds from the sale of the Class B Units and the common units to fund a portion of the cash purchase price for the Chief Acquisition. The remainder of the purchase price was funded by a portion of the $600 million of senior notes issued in a private placement in May 2012.

Eastern Midstream

The Chief Acquisition complements our existing gathering system infrastructure in Pennsylvania. Excluding the Chief Acquisition, we spent approximately $235.8 million in the first nine months of 2012 constructing gathering systems, trunklines and

compressor stations. As a result, our average system volumes increased from 344 MMcfd in the second quarter of 2012 to 456 MMcfd in the third quarter of 2012. Construction activities in our Eastern Midstream segment were concentrated on the development of our Wyoming pipeline, which we completed on September 30, 2012, and the continued construction of Phase III of our Lycoming system. We expect significant development activities to continue through 2013.

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale region. The 12 inch water pipeline will largely parallel the trunk line of our existing gathering system in Lycoming County. The initial 12 mile section of the water line became operational in March 2012 and further construction is progressing in conjunction with Phase III of our Lycoming system.

Midcontinent Midstream

In July 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant in east Texas for $62.3 million, net of transaction costs. It included approximately eight miles of a gas gathering pipeline, an 80 MMcfd processing plant, approximately 20 miles of NGL pipeline and a 50% ownership in an approximately 11 mile residue gas pipeline.

Our Panhandle system volumes continue to increase as development in the Granite Wash region continues at a strong pace. For the three months ended September 30, 2012 and 2011, Panhandle system volumes were 360 MMcfd compared to 342 MMcfd. For the nine months ended September 30, 2012 and 2011, Panhandle system volumes were 349 MMcfd compared to 308 MMcfd on the Panhandle system. With the expansion at our Antelope Hills facility, we are now able to process all of the volumes gathered on our Panhandle system. We anticipate being able to process all of our Panhandle system supply without any processing capacity constraints through the remainder of 2012.

During the first quarter, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets in the Midcontinent Midstream segment located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). The impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented a de minimis amount of our consolidated total revenues for the three months ended March 31, 2012 and 2011.

2012 Commodity Prices

Revenues, profitability and the future rate of growth of our Midcontinent Midstream segment is highly dependent on market demand and prevailing NGL and natural gas prices. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas. We continually monitor commodity prices and when it appears opportunistic, we may choose to use derivative financial instruments to hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. We currently have three commodity derivatives, all of which expire at the end of 2012.

Results of Operations

Consolidated Review

The following table presents summary consolidated results for the periods presented:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues	$	268,847		$	308,352		$	738,176		$	872,201
Expenses		(208,356	)		(270,777	)		(758,842	)		(753,464	)

Operating income (loss)		60,491			37,575			(20,666	)		118,737
Other income (expense)		(21,708	)		(1,718	)		(43,086	)		(39,711	)

Net income (loss)		38,783			35,857			(63,752	)		79,026
Noncontrolling interest		—			—			—			664

Net Income (loss) attributable to PVR Partners, L.P.	$	38,783		$	35,857		$	(63,752	)	$	79,690

Eastern Midstream Segment

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Eastern Midstream segment and the percentage change for the periods presented:


	Three Months Ended September 30,				Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	2012		2011		Favorable (Unfavorable)			% Change Favorable (Unfavorable)
Financial Highlights
Revenues
Gathering and transportation fees	$	25,759	$	7,720	$	18,039			234	%
Other		1,041		—		1,041			N/A

Total revenues		26,800		7,720		19,080			247	%


Expenses
Operating		2,124		635		(1,489	)		(234	%)
General and administrative		3,236		502		(2,734	)		(545	%)
Depreciation and amortization		11,867		987		(10,880	)		(1102	%)

Total operating expenses		17,227		2,124		(15,103	)		(711	%)


Operating income	$	9,573	$	5,596	$	3,977			71	%


Operating Statistics
Daily throughput volumes (MMcfd)		456		63		393			624	%

Revenues

As previously disclosed, the Chief Acquisition closed on May 17, 2012 with a purchase price of approximately $1.0 billion. Chief Gathering owned and operated six natural gas gathering systems serving over 300,000 dedicated acres in the Marcellus Shale, located in the north central Pennsylvania counties of Lycoming, Bradford, Susquehanna, Sullivan, Wyoming and Greene and in Preston County, West Virginia. This transaction resulted in a major expansion of our pipeline systems in our Eastern Midstream segment.

We continue to develop other areas of the Marcellus Shale in Pennsylvania as well as expand the gathering and pipeline systems acquired from Chief Gathering. We began construction of the Phase III extension of our Lycoming system which will expand our existing footprint in that area. As a result of our expansion activities and the Chief Acquisition, we are separately reporting the results of the operations of our Eastern Midstream segment which was previously combined with our Midcontinent Midstream reporting segment. Historical results from the Eastern Midstream segment have been reclassified from the Midcontinent Midstream segment for comparative purposes.

Gathering and transportation fees have increased due to the significant increase in volumes. The development and completion of our expansion projects within the past year have added significant volumes to the system. In addition, the volumes and related fees from the Chief Acquisition contributed to the increase.

Other revenue primarily represented operations from our investment in a joint venture and related management fees. In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale region. The initial 12 mile section of the water line became operational in March 2012 and water line expansion continues in conjunction with construction of Phase III of our Lycoming system. In addition, we receive a fee for managing certain projects of the joint venture and an accounting services fee. The fees recognized in revenues were after intercompany eliminations.

Expenses

Operating expenses increased due to prior and current years’ expansion projects and the Chief Acquisition. The related costs of these facilities included increased field salaries, supplies, contract services and property taxes.

General and administrative expenses increased due to the addition of personnel in our Williamsport, Pennsylvania office, increased equity compensation and corporate overhead.

Depreciation and amortization expenses increased as a result of acquisitions and capital expansions.

Eastern Midstream Segment

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Eastern Midstream segment and the percentage change for the periods presented:


	Nine Months Ended September 30,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Gathering and transportation fees	$	56,710	$	16,582	$	40,128			242	%
Other		2,687		—		2,687			N/A

Total revenues		59,397		16,582		42,815			258	%


Expenses
Operating		4,211		898		(3,313	)		(369	%)
General and administrative		6,126		1,137		(4,989	)		(439	%)
Acquisition related costs		14,049		—		(14,049	)		N/A
Depreciation and amortization		22,322		2,151		(20,171	)		(938	%)

Total operating expenses		46,708		4,186		(42,522	)		(1016	%)


Operating income	$	12,689	$	12,396	$	293			2	%


Operating Statistics
Daily throughput volumes (MMcfd)		337		47		290			617	%

Revenues

Other revenue primarily represented operations from our investment in a joint venture and related management fees. In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale region. The initial 12 mile section of the water line became operational in March 2012 and water line expansion in conjunction with construction of Phase III of our Lycoming system. In addition, we receive a fee for managing certain projects of the joint venture and an accounting services fee. The fees recognized in revenues were after intercompany eliminations.

Expenses

General and administrative expenses increased due to the addition of personnel in our Williamsport, Pennsylvania office, increased equity compensation and corporate overhead.

Acquisition costs increased due to the one-time expenses of the Chief Acquisition, which included investment banking, legal and due diligence fees and expenses.

Depreciation and amortization expenses increased as a result of acquisitions and capital expansions.

Midcontinent Midstream Segment

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Midcontinent Midstream segment and the percentage change for the periods presented:


	Three Months Ended September 30,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	78,026	$	120,240	$	(42,214	)		(35	%)
Natural gas liquids		96,237		129,389		(33,152	)		(26	%)
Gathering and transportation fees		1,470		2,361		(891	)		(38	%)
Gain on sale of plant		31,292		—		31,292			N/A
Other		497		1,186		(689	)		(58	%)

Total revenues		207,522		253,176		(45,654	)		(18	%)


Expenses
Cost of gas purchased		147,246		223,762		76,516			34	%
Operating		11,164		10,880		(284	)		(3	%)
General and administrative		4,826		4,482		(344	)		(8	%)
Depreciation and amortization		11,913		11,904		(9	)		(0	%)

Total operating expenses		175,149		251,028		75,879			30	%


Operating income	$	32,373	$	2,148	$	30,225			1407	%


Operating Statistics
Daily throughput volumes (MMcfd)		410		441		(31	)		(7	%)

Revenues

Revenues primarily included residue gas sold from processing plants after natural gas liquids (“NGLs”) were removed, NGLs sold after being removed from system throughput volumes received, gathering and transportation fees.

Natural gas revenues decreased primarily due to lower prices and a migration to more fee based contracts. The average natural gas spot price decreased 35%, from $4.35 in the third quarter of 2011 compared to $2.81 in the comparable period of 2012. The decrease in natural gas revenues was partially offset by an increase in volumes on the Panhandle system. We also had a decrease in throughput volumes due to the sale of the Crossroads plant at the beginning of July. The Crossroads plant processed approximately 48 MMcfd in the third quarter of 2011.

NGL and condensate revenues decreased primarily due to the prices received. Our average realized price received for a hypothetical Conway NGL barrel in the third quarter of 2012 was $29.53 compared to $47.90 for the comparable period of 2011. NGL and condensate prices can fluctuate significantly based on market conditions in certain areas. In order to obtain favorable pricing, we sell our NGLs and condensate to several customers in multiple markets.

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million after transaction costs. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, included approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized.

Other revenues included earnings from a natural gas gathering joint venture in Wyoming and marketing fees we earned from selling natural gas. The decrease in other revenues was primarily due to the loss of a significant marketing contract in the last half of 2011 and lower earnings from our joint venture, which had decreased volumes.

Expenses

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The amounts we pay producers fluctuate each period due to the volumes related to each type of processing contract. Recently, we have entered into more fee based contracts to reduce our commodity exposure. The average natural gas spot price decreased $1.54, or 35%, from $4.35 in the third quarter of 2011 compared to $2.81 in the comparable period of 2012. The decrease was partially offset by an increase in volumes on the Panhandle system.

Operating expenses increased primarily due to employee costs and supplies to run the expanded facilities.

General and administrative expenses increased primarily due to employee related costs, offset by a reduction in the allocation of corporate overhead. We added the Eastern Midstream segment in the second quarter of 2012 due to the Chief Acquisition and our expansion activities in Pennsylvania. As a result of the expansion, the new segment assumed a greater portion of the corporate overhead allocation.

Midcontinent Midstream Segment

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Midcontinent Midstream segment and the percentage change for the periods presented:


	Nine Months Ended September 30,					Favorable			% Change Favorable
	2012			2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	215,780		$	324,447	$	(108,667	)		(33	%)
Natural gas liquids		316,161			374,279		(58,118	)		(16	%)
Gathering and transportation fees		5,778			7,590		(1,812	)		(24	%)
Gain on sale of plant		31,292			—		31,292			N/A
Other		2,042			4,874		(2,832	)		(58	%)

Total revenues		571,053			711,190		(140,137	)		(20	%)


Expenses
Cost of gas purchased		453,543			613,295		159,752			26	%
Operating		31,642			30,399		(1,243	)		(4	%)
General and administrative		16,575			16,412		(163	)		(1	%)
Impairments		124,845			—		(124,845	)		N/A
Depreciation and amortization		37,220			35,228		(1,992	)		(6	%)

Total operating expenses		663,825			695,334		31,509			5	%


Operating income (loss)	$	(92,772	)	$	15,856	$	(108,628	)		(685	%)


Operating Statistics
Daily throughput volumes (MMcfd)		435			415		20			5	%

Revenues

Revenues primarily included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, gathering and transportation fees.

Natural gas revenues decreased primarily due to lower prices and a migration to more fee based contracts. The average natural gas spot price decreased 39%, from $4.27 in the first nine months of 2011 to $2.59 in the comparable period of 2012. The decrease in natural gas revenues was partially offset by an increase in volumes on the Panhandle system. Offsetting the total throughput volumes was the sale of the Crossroads plant at the beginning of July. The Crossroads plant processed approximately 54 MMcfd during the nine months ended September 30, 2011. The plant processed approximately 55 MMcfd through the first half of 2012 prior to being sold.

NGL and condensate revenues decreased primarily due to the prices received. Our average realized price received for a hypothetical Conway NGL barrel in the first nine months of 2012 was $33.64 compared to $48.64 for the comparable period of 2011. NGL and condensate prices have significant fluctuations based on market conditions in certain areas. In order to obtain favorable pricing, we sell our NGLs and condensate to several customers in multiple markets.

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million after transaction costs. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized.

Expenses

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The amounts we pay producers fluctuate each period due to the volumes related to each type of processing contract. Recently, we have entered into more fee based contracts to reduce our commodity exposure. The average natural gas spot price decreased $1.68, or 39%, from $4.27 in the first nine months of 2011 to $2.59 in the comparable period of 2012. The decrease was partially offset by an increase in volumes on the Panhandle system.

Operating expenses increased due to increases in chemical and treating expenses during 2012 and higher employee costs, which were the result of a new plant and expansion efforts completed in the Panhandle system during 2012.

General and administrative expenses decreased primarily due to a reduction in the allocation of corporate overhead. We added the Eastern Midstream segment in the second quarter of 2012 due to the Chief Acquisition and our expansion activities in Pennsylvania. As a result of the acquisition and expansion, the new segment assumed a greater portion of the corporate overhead allocation. This reduction is offset by higher employee costs.

As previously disclosed, an impairment charge against the book value of the North Texas gathering system assets was recognized during the first quarter of 2012. The non-cash charge of $124.8 million was triggered by continuing declines in natural gas prices and lack of drilling in the southern portion of the Fort Worth Basin served by the system.

Depreciation and amortization expense increased primarily due to expansion efforts, offset by reduced depreciation and amortization from the North Texas gathering system assets.

Coal and Natural Resource Management Segment

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Coal and Natural Resource Management segment and the percentage change for the periods presented:


	Three Months Ended September 30,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	28,760	$	40,977	$	(12,217	)		(30	%)
Other		5,765		6,479		(714	)		(11	%)

Total revenues		34,525		47,456		(12,931	)		(27	%)


Expenses
Operating		4,299		4,282		(17	)		(0	%)
General and administrative		3,469		3,771		302			8	%
Depreciation, depletion and amortization		8,212		9,572		1,360			14	%

Total expenses		15,980		17,625		1,645			9	%


Operating income	$	18,545	$	29,831	$	(11,286	)		(38	%)


Other data

Coal royalty tons		7,703		9,479		(1,776	)		(19	%)

Average coal royalties per ton	$	3.73	$	4.32	$	(0.59	)		(14	%)

Revenues

Coal royalties, which accounted for 83% of the Coal and Natural Resource Management segment revenues for the three months ended September 30, 2012 and 86% for the three months ended 2011, were lower in 2012 as compared to 2011. The decrease was a result of less coal being produced by our lessees and lower coal prices. The reduced demand for coal from our lessees’ customers was primarily due to domestic electrical generation switching from coal to natural gas. Coal royalties per ton decreased because customers cannot utilize all of the coal they have purchased. The surplus has caused lower demand, decreased production and reduced prices.

Other revenues primarily consist of coal services, oil and gas royalties and timber sales. The decrease in other revenues was primarily due to lower coal services and oil and gas royalties. Throughput fees from coal services decreased, which was consistent with the decrease in coal production. Oil and gas royalties were lower due to lower natural gas prices and a one-time settlement received in the third quarter of 2011.

Expenses

Operating expenses remained relatively constant.

DD&A expenses decreased for the comparative periods as a result of the decrease in coal production and the related depletion expense.

Coal and Natural Resource Management Segment

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

The following table sets forth a summary of certain financial and other data for our Coal and Natural Resource Management segment and the percentage change for the periods presented:


	Nine Months Ended September 30,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	91,150	$	124,546	$	(33,396	)		(27	%)
Other		16,576		19,883		(3,307	)		(17	%)

Total revenues		107,726		144,429		(36,703	)		(25	%)


Expenses
Operating		11,677		11,815		138			1	%
General and administrative		11,873		14,151		2,278			16	%
Depreciation, depletion and amortization		24,759		27,978		3,219			12	%

Total expenses		48,309		53,944		5,635			10	%


Operating income	$	59,417	$	90,485	$	(31,068	)		(34	%)


Other data

Coal royalty tons		23,584		29,501		(5,917	)		(20	%)

Average coal royalties per ton	$	3.86	$	4.22	$	(0.36	)		(9	%)

Revenues

Coal royalties, which accounted for 85% of the Coal and Natural Resource Management segment revenues for the nine months ended September 30, 2012 and 86% for the same period in 2011, were lower in 2012 as compared to 2011. The decrease was a result of less coal being produced by our lessees and lower coal prices. The reduced demand for coal from our lessees’ customers was primarily due to domestic electrical generation switching from coal to natural gas and a mild winter. Coal royalties per ton decreased because customers cannot utilize all of the coal they have purchased. The surplus has caused lower demand, decreased production and reduced prices.

Expenses

Operating expenses remained relatively constant.

General and administrative expenses decreased primarily due to lower employee related costs and a reduction in the allocation of corporate overhead. The reduction in employee related costs was the result of a decrease in incentive compensation due to the segment’s financial performance in the first nine months of 2012. Corporate overhead decreased primarily due to the addition of the Eastern Midstream segment in the second quarter of 2012. As a result of the expansion, the new segment assumed a greater portion of the corporate overhead allocation.

DD&A expenses decreased for the comparative periods as a result of the decrease in coal production and the related depletion expense.

Other

Our other results primarily consist of interest expense and net derivative gains (losses). The following table sets forth a summary of certain financial data for our other results for the periods presented:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Operating income (loss)	$	60,491		$	37,575		$	(20,666	)	$	118,737
Other income (expense)
Interest expense		(20,288	)		(10,528	)		(45,616	)		(33,806	)
Derivatives		(1,524	)		8,690			2,201			(6,289	)
Other		104			120			329			384

Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026

Interest Expense. Interest expense for the three and nine months ended September 30, 2012 increased compared to the same periods in 2011. The overall net increase was due to the new Senior Notes. Also, there was an increase in Revolver interest expense related to increased LIBOR and related margins paid on outstanding debt. Our amortization of debt issuance costs increased in the comparable third quarter periods due to the Revolver amendment and issuance of the new Senior Notes. Our year-to-date debt issuance costs decreased from the prior year due to a Revolver amendment and a change in the bank group in 2011, which caused a partial write off of debt issuance costs in 2011. These increases were partially offset by interest we have capitalized related to construction efforts primarily on the Eastern Midstream and Midcontinent segments.

Our consolidated interest expense for the periods presented is comprised of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
Source	2012			2011			2012			2011
Interest on Revolver and bank fees	$	(5,345	)	$	(4,220	)	$	(15,322	)	$	(12,290	)
Interest on Senior Notes		(18,750	)		(6,188	)		(37,267	)		(18,563	)
Debt issuance costs and other		(1,589	)		(1,040	)		(4,217	)		(4,735	)
Capitalized interest		5,396			920			11,190			1,782

Total interest expense	$	(20,288	)	$	(10,528	)	$	(45,616	)	$	(33,806	)

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas prices, as well as interest rates.

Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements using discounted cash flows using quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk for derivatives in a liability position.

Our derivative activity for the periods presented is summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Interest Rate Swap realized derivative loss	$	(414	)	$	(1,973	)	$	(1,213	)	$	(5,849	)
Interest Rate Swap unrealized derivative gain		384			1,957			1,012			5,259
Interest Rate Swap other comprehensive income reclass		201			(42	)		523			(366	)
Natural gas midstream commodity realized derivative loss		(918	)		(4,726	)		(7,365	)		(13,628	)
Natural gas midstream commodity unrealized derivative gain (loss)		(777	)		13,474			9,244			8,295

Total derivative gain (loss)	$	(1,524	)	$	8,690		$	2,201		$	(6,289	)

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from debt and equity offerings. We satisfy our debt service obligations and distributions to unitholders solely using cash generated from our operations. We believe that the cash

generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments and distributions. However, our ability to meet these requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, most of which are beyond our control.

On May 17, 2012, we acquired Chief Gathering for a base purchase price of approximately $1.0 billion, paid to Chief in a combination of $849.3 million in cash and fair value of $191.3 million of a new class of limited partner interests in the Partnership. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Future Capital Needs and Commitments.”

The following table summarizes our statements of cash flow for the periods presented:


	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(63,752	)	$	79,026
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		175,148			63,435
Net changes in operating assets and liabilities		23,396			(153	)

Net cash provided by operating activities		134,792			142,308
Net cash used in investing activities (summarized)		(1,157,326	)		(261,373	)
Net cash provided by financing activities (summarized)		1,024,021			117,009

Net increase (decrease) in cash and cash equivalents	$	1,487		$	(2,056	)

Cash Flows From Operating Activities

The overall decrease in net cash provided by operating activities in the nine months ended September 30, 2012 as compared to the same period in 2011 was primarily driven by a decrease in coal royalties and decreased Midcontinent Midstream margins affected by lower commodity pricing, offset by increased fee-based revenues related to the Eastern Midstream segment. Additionally, there was a decrease in cash distributions received from our joint ventures and increases in operating expenses and acquisition related costs.

Cash Flows From Investing Activities

Net cash used in investing activities was primarily for capital expenditures. The following table sets forth our capital expenditures program, by segment, for the periods presented:


	Nine Months Ended September 30,
	2012		2011
Eastern Midstream
Acquisitions (1)	$	1,040,564	$	—
Internal growth		234,803		69,940
Maintenance		1,019		398

Total		1,276,386		70,338


Midcontinent Midstream
Acquisitions	$	—	$	12,243
Internal growth		84,458		57,558
Maintenance		11,168		7,447

Total		95,626		77,248


Coal and Natural Resource Management
Acquisitions (2)	$	836	$	111,976
Internal growth		113		—
Maintenance		10		687

Total		959		112,663


Total capital expenditures	$	1,372,971	$	260,249

(1)	Includes cash expenditures recorded based upon the purchase price allocation in property plant and equipment, intangibles and goodwill. Amounts include $0.4 million of notes receivable, $622.0 million in intangible assets and $70.3 million of goodwill.

(2)	In January 2011, we completed the acquisition of the Middle Fork properties, which added significant reserves to our Coal and Natural Resource Management segment in the Central Appalachia region.

Our Eastern Midstream and Midcontinent Midstream segments’ capital expenditures for the nine months ended September 30, 2012 and 2011 consisted primarily of the Chief Acquisition and internal growth capital to expand our natural gas gathering and operational footprint in our Marcellus Shale and Panhandle systems.

Cash Flows From Financing Activities

During the nine months ended September 30, 2012, we received funds from the issuance of $600 million in new Senior Notes and $577.7 million from the issuance of Class B Units and common units to institutional investors in private equity offerings. A majority of the funds were used to finance the Chief Acquisition and the remainder was used to pay down a portion of the Revolver. During the nine months ended September 30, 2011, we incurred net borrowings of $227.0 million to fund our coal and natural resources acquisitions and to finance the construction of natural gas midstream projects.

During the nine months ended September 30, 2012 and 2011, we paid cash distributions to our unitholders of $128.5 million and $99.7 million.

Certain Non-GAAP Financial Measures

We use non-GAAP (Generally Accepted Accounting Principles) measures to evaluate our business and performance. None of these measures should be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Reconciliation of Non-GAAP “Segment Adjusted EBITDA” to GAAP “Net income (loss)”:

Segment Adjusted EBITDA (a):
Eastern Midstream	$	21,440		$	6,583		$	49,060		$	14,547
Midcontinent Midstream		12,994			14,052			38,001			51,084
Coal and Natural Resource Management		26,757			39,403			84,176			118,463

Total segment adjusted EBITDA	$	61,191		$	60,038		$	171,237		$	184,094
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(31,992	)		(22,463	)		(84,301	)		(65,357	)
Impairments		—			—			(124,845	)		—
Acquisition related costs		—			—			(14,049	)		—
Gain on sale of plant		31,292			—			31,292			—
Interest expense		(20,288	)		(10,528	)		(45,616	)		(33,806	)
Derivatives		(1,524	)		8,690			2,201			(6,289	)
Other		104			120			329			384

Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026
Depreciation, depletion and amortization		31,992			22,463			84,301			65,357
Impairment		—			—			124,845			—
Acquisition related costs		—			—			14,049			—
Gain on sale of plant		(31,292	)		—			(31,292	)		—
Derivative contracts:
Derivative losses included in net income		1,524			(8,690	)		(2,201	)		6,289
Cash payments to settle derivatives for the period		(1,332	)		(6,699	)		(8,578	)		(19,477	)
Equity earnings from joint ventures, net of distributions		697			2,818			142			4,635
Maintenance capital expenditures		(3,749	)		(2,884	)		(12,197	)		(8,532	)
Replacement capital expenditures		(6,725	)		(6,725	)		(20,175	)		(20,175	)


Distributable cash flow (b)	$	29,898		$	36,140		$	85,142		$	107,123


Distribution to Partners:

Total cash distribution paid during the period	$	46,833		$	34,887		$	128,516		$	99,696


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Net income as adjusted”:
Net income (loss)	$	38,783		$	35,857		$	(63,752	)	$	79,026
Impairments		—			—			124,845			—
Acquisition related costs		—			—			14,049			—
Gain on sale of plant		(31,292	)		—			(31,292	)		—
Adjustments for derivatives:
Derivative losses included in net income		1,524			(8,690	)		(2,201	)		6,289
Cash payments to settle derivatives for the period		(1,332	)		(6,699	)		(8,578	)		(19,477	)


Net income, as adjusted (c)	$	7,683		$	20,468		$	33,071		$	65,838

(a)

Adjusted EBITDA, or earnings before interest, tax and depreciation, depletion and amortization (“DD&A”), represents operating income plus DD&A, plus impairments, plus acquisition related costs, minus gain on sale of plant. We believe EBITDA or a version of Adjusted EBITDA is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream and coal industries. We use this information for comparative purposes within the industry. EBITDA is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

(b)	Distributable cash flow represents net income plus DD&A, plus impairments, plus acquisition related costs, minus gain on sale of plant, plus (minus) derivative losses (gains) included in net income, plus (minus) cash received (paid) for derivative

settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures, minus replacement capital expenditures. Distributable cash flow is also the quantitative standard used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.

(c)

Net income, as adjusted, represents net income adjusted to exclude the effects of impairments, one-time charges related to acquisitions, gains on sale of plants and non-cash changes in the fair value of derivatives. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. We use this information for comparative purposes within the industry. Net income, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

Sources of Liquidity

Long-Term Debt

Revolver. As of September 30, 2012, net of outstanding indebtedness of $535.0 million and letters of credit of $7.9 million, we had remaining borrowing capacity of $457.1 million on the Revolver. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2012 was approximately 3.3%. We do not have a public rating for the Revolver. As of September 30, 2012, we were in compliance with all covenants under the Revolver.

Interest Rate Swaps. We have entered into interest rate swaps, or the Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the Interest Rate Swap positions as of September 30, 2012:


	Notional Amounts		Swap Interest Rates (1)
Term	(in millions)		Pay			Receive

October 2012 - December 2012	$	100.0		2.09	%	LIBOR

(1)	References to LIBOR represent the 3-month rate.

After considering the applicable margin of 3.50% in effect as of September 30, 2012, the total interest rate on the $100.0 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.59% as of September 30, 2012.

Senior Notes. In May 2012, we sold $600.0 million of senior notes due on September 1, 2020 with an annual interest rate of 8.375% (the “Senior Notes”), payable semi-annually in arrears on September 1 and December 1 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.375%. The Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our current and future subsidiaries, which are also guarantors under the Revolver.

Equity

Class B Units. In May 2012, we sold a new class of PVR limited partner interests to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. for $400.0 million (the “Class B Units”). These units are substantially similar in all respects to our common units, except that we will pay distributions in respect of the Class B Units, until they convert into common units, through the issuance of additional Class B Units rather than cash unless we so elect to pay distributions in cash. On or after July 1, 2014, at the option of either PVR or Riverstone, the Class B Units will convert into common units on a one-for-one basis. A portion of the Class B Units may convert to common units prior to July 1, 2014 if the weighted average market price of common units exceeds certain thresholds.

Common Units. In May 2012, we sold common units to institutional investors in a private placement in the amount of $177.7 million, net of offering costs.

Special Units. In May 2012, we issued a new class of PVR limited partner interests to Chief Gathering with a fair value of $191.3 million in connection with the Chief Acquisition (the “Special Units”). The Special Units are substantially similar to our common units, except that the Special Units will neither pay nor accrue distributions for six consecutive quarters commencing after

the closing of the Chief Acquisition. The Special Units will automatically convert into common units on a one-for-one basis on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013.

Future Capital Needs and Commitments

As of September 30, 2012, our remaining borrowing capacity under the $1.0 billion Revolver of approximately $457.1 million is sufficient to meet our anticipated 2012 capital needs and commitments (other than major acquisitions). Our short-term cash requirements for operating expenses and quarterly distributions to our unitholders are expected to be funded through operating cash flows. In 2012, we expect to invest approximately $470-500 million in internal growth capital, excluding acquisitions. A significant portion of the internal growth capital expenditures is related to the Marcellus Shale system, which includes the Chief Acquisition. Long-term cash requirements for acquisitions and internal growth capital are expected to be funded by operating cash flows, borrowings under the Revolver and issuances of additional debt and equity securities.

Part of our long-term strategy is to increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating.

Environmental Matters

Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.

As of September 30, 2012 and December 31, 2011, our environmental liabilities were $0.7 million and $0.8 million, which represents our best estimate of the liabilities as of those dates related to our Coal and Natural Resource Management, Eastern Midstream and Midcontinent Midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates which involve the judgment of our management were fully disclosed in PVR’s Annual Reports on Form 10-K for the year ended December 31, 2011 and remained unchanged as of September 30, 2012.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are as follows:

•

Price Volatility

•

Interest Rate Risk

•

Customer Credit Risk

We are indirectly exposed to the credit risk of our customers and lessees. If our customers or lessees become financially insolvent, they may or not be able to continue to operate or meet their payment obligations.

As a result of our risk management activities as discussed below, we could potentially be exposed to counterparty risk with financial institutions with whom we enter into these risk management positions.

We have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and

equipment, intangibles and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could record a significant impairment loss on our Consolidated Statements of Operations.

Price Volatility

In order to manage our exposure to price volatility in the marketing of our natural gas and NGLs, we continually monitor commodity prices and when it is opportunistic we may choose to enter into condensate, natural gas or NGL price hedging arrangements with respect to a portion of our expected production. Historically, our hedges are limited in duration, usually for periods of two years or less, and we have utilized derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price volatility associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our Midcontinent Midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our price volatility management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At September 30, 2012, we reported a commodity derivative liability related to the Midcontinent Midstream segment of $1.4 million that is with three counterparties and is substantially concentrated with one of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

For the three months ended September 30, 2012 we reported a net loss for both commodity and Interest Rate Swaps of $1.5 million and a net gain for the nine months ended September 30, 2012 of $2.2 million. We recognize changes in fair value in earnings currently in the derivatives caption on our Consolidated Statements of Operations. We have experienced and could continue to experience significant changes in the estimate of derivative gains and losses recognized due to fluctuations in the value of our derivative contracts. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices, and interest rates. These fluctuations could be significant in a volatile environment.

The following table lists our commodity derivative agreements for the period presented:


	Average Volume				Weighted Average Price				Fair Value at September 30,
	Per Day		Swap Price		Put		Call		2012

NGL - natural gasoline collar		(gallons)				(per gallon)
Fourth quarter 2012		54,000			$	1.75	$	2.02	$	(265	)

Crude oil swap		(barrels)		(per barrel)
Fourth quarter 2012		600	$	88.62						(225	)

Natural gas purchase swap		(MMBtu)		(MMBtu)
Fourth quarter 2012		4,000	$	5.195						(688	)

Settlements to be paid in subsequent period										(187	)

									$	(1,365	)

We estimate that a $5.00 per barrel increase or decrease in the crude oil price would increase or decrease the fair value of our crude oil swap by $0.3 million. We estimate that a $1.00 per MMBtu increase or decrease in the natural gas price would decrease or increase the fair value of our natural gas purchase swap by $0.2 million. We estimate that a $0.10 per gallon increase in the natural gasoline (an NGL) price would increase the fair value of our natural gasoline collar by $0.3 million. We estimate that a $0.10 per gallon decrease in the natural gasoline (an NGL) price would decrease the fair value of our natural gasoline collar by $0.2 million.

Based on historical correlations, we estimate that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, our natural gas midstream gross margin and operating income (loss) for the remainder of 2012 would increase or decrease by $0.1 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income (loss) for the remainder of 2012 would increase or decrease by $2.0 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in our gross margin and operating income (loss) exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of September 30, 2012, we had $535.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the Revolver. From September 2012 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, or 19% of our outstanding indebtedness under the Revolver as of September 30, 2012, with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through the Interest Rate Swaps) as of September 30, 2012 would cost us approximately $4.4 million in additional interest expense per year.

Customer Credit Risk

This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency of any of these customers could have a significant impact on our results of operations. If our customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay, and maintain reserves we believe are adequate to cover exposure for uncollectible accounts. As of September 30, 2012, no receivables were collateralized, and we had a $1.0 million allowance for doubtful accounts, of which the majority related to our Coal and Natural Resource Management segment.

Item 4

Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2012. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2012, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

On September 1, 2012, we upgraded our enterprise resource planning (“ERP”) system. We believe there were no negative effects on our internal control over financial reporting as a result of this upgrade. Except for the upgrade, no changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item I.

Legal Proceedings.

For information on legal proceedings, see Part I, Item I, Financial Statements, Note 11, “Commitments and Contingencies” in the Notes to Unaudited Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item IA.

Risk Factors.

There have been no material changes from the risk factors described previously in Part I, Item IA of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 24, 2012.

Item 6

Exhibits


3.1		Certificate of Amendment to Certificate of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on August 17, 2012).

3.2		Amendment No. 1 to the Fifth Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on August 17, 2012).

3.3		Certificate of Amendment to Certificate of Formation of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.3 to Registrant’s Current Report on Form 8-K filed on August 17, 2012).

3.4		Amendment No. 1 to the Sixth Amended and Restated Limited Liability Company Agreement of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.4 to Registrant’s Current Report on Form 8-K filed on August 17, 2012).

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1*		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101†		The following financial information from the quarterly report on Form 10-Q of PVR Partners L.P. for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Operations, (ii) Consolidated Comprehensive Income (Loss) (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.

*	Furnished herewith.

**	Filed herewith.

†

The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act, are deemed not filed for purposes of the Exchange Act and are otherwise not subject to liability under these sections.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	PVR PARTNERS, L.P.

	By:	PVR GP, LLC

Date: October 29, 2012	By:	/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer

Date: October 29, 2012	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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