PVR PARTNERS, L. P. - FORM 10-Q

PVR PARTNERS, L. P. - FORM 10-Q - May 7, 2012

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file	filename
EXCEL - IDEA: XBRL DOCUMENT - PVR PARTNERS, L. P.	Financial_Report.xls
EX-32.1 - SECTION 906 CEO CERTIFICATION - PVR PARTNERS, L. P.	d322862dex321.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - PVR PARTNERS, L. P.	d322862dex312.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - PVR PARTNERS, L. P.	d322862dex322.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - PVR PARTNERS, L. P.	d322862dex311.htm
EX-12.1 - STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES CALCULATION - PVR PARTNERS, L. P.	d322862dex121.htm

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 March 31, 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

PENN VIRGINIA RESOURCE 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)

(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 April 06, 2012, 79,082,088 common units representing limited partner interests were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX


		Page
PART I.	Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011		1

	Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2012 and 2011		1

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

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		3

	Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2012 and 2011		4

	Notes to Consolidated Financial Statements		5

	Forward-Looking Statements		12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		23

Item 4.	Controls and Procedures		25

PART II.	Other Information

Item 1.	Legal Proceedings		26

Item 1A.	Risk Factors		26

Item 6.	Exhibits		26

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per unit data)


	Three Months Ended March 31,
	2012			2011
Revenues
Natural gas midstream	$	206,276		$	206,281
Coal royalties		33,159			38,991
Other		6,982			8,255

Total revenues		246,417			253,527


Expenses
Cost of gas purchased		165,464			170,255
Operating		15,903			13,073
General and administrative		12,044			10,970
Impairments		124,845			—
Depreciation, depletion and amortization		23,853			21,244

Total expenses		342,109			215,542


Operating income (loss)		(95,692	)		37,985

Other income (expense)
Interest expense		(9,817	)		(10,850	)
Derivatives		(4,951	)		(19,761	)
Other		116			137


Net income (loss)	$	(110,344	)	$	7,511
Net loss attributable to noncontrolling interests, pre-merger		—			664

Net income (loss) attributable to Penn Virginia Resource Partners, L.P.	$	(110,344	)	$	8,175


Basic net income (loss) per limited partner unit	$	(1.39	)	$	0.17
Diluted net income (loss) per limited partner unit	$	(1.39	)	$	0.17

Weighted average number of units outstanding, basic		79,301			46,426
Weighted average number of units outstanding, diluted		79,340			46,426

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – unaudited

(in thousands)


	Three Months Ended March 31,
	2012			2011

Net income (loss)	$	(110,344	)	$	7,511
Reclassification adjustment for derivative activities		(147	)		189

Comprehensive income (loss)	$	(110,491	)	$	7,700

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	March 31, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents	$	7,530		$	8,640
Accounts receivable, net of allowance for doubtful accounts		89,540			101,340
Other current assets		5,273			5,640

Total current assets		102,343			115,620


Property, plant and equipment		1,674,677			1,689,256
Accumulated depreciation, depletion and amortization		(411,921	)		(406,959	)

Net property, plant and equipment		1,262,756			1,282,297


Equity investments		88,503			81,162
Intangible assets (net of accumulated amortization of $25,398 and $38,587)		14,654			70,665
Other long-term assets		42,927			44,248


Total assets	$	1,511,183		$	1,593,992


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	112,755		$	124,082
Deferred income		3,349			3,416
Derivative liabilities		13,499			12,042

Total current liabilities		129,603			139,540


Deferred income		11,319			10,492
Other liabilities		21,060			21,256
Senior notes		300,000			300,000
Revolving credit facility		617,000			541,000

Partners’ capital
Common units		431,605			580,961
Accumulated other comprehensive income		596			743

Total partners’ capital		432,201			581,704


Total liabilities and partners’ capital	$	1,511,183		$	1,593,992

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended March 31,
	2012			2011

Cash flows from operating activities
Net income (loss)	$	(110,344	)	$	7,511
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,853			21,244
Impairments		124,845			—
Derivative Contracts:
Total derivative losses		4,951			19,761
Cash payments to settle derivatives		(3,641	)		(4,858	)
Non-cash interest expense		1,049			1,040
Non-cash unit-based compensation		2,038			821
Equity earnings, net of distributions received		(741	)		3,160
Other		(647	)		(147	)
Changes in operating assets and liabilities
Accounts receivable		11,814			(1,795	)
Accounts payable and accrued liabilities		(8,892	)		8,421
Deferred income		760			(147	)
Other assets and liabilities		122			(203	)

Net cash provided by operating activities		45,167			54,808


Cash flows from investing activities
Acquisitions		(196	)		(95,216	)
Additions to property, plant and equipment		(75,373	)		(37,451	)
Other		(6,290	)		1,007

Net cash used in investing activities		(81,859	)		(131,660	)


Cash flows from financing activities
Distributions to partners		(40,418	)		(30,633	)
Proceeds from borrowings		86,000			120,000
Repayments of borrowings		(10,000	)		(13,000	)
Cash paid for merger		—			(1,004	)

Net cash provided by financing activities		35,582			75,363


Net decrease in cash and cash equivalents		(1,110	)		(1,489	)
Cash and cash equivalents – beginning of period		8,640			15,964

Cash and cash equivalents – end of period	$	7,530		$	14,475


Supplemental disclosure:
Cash paid for interest	$	4,694		$	5,616

Noncash investing activities:
Other liabilities related to acquisitions	$	—		$	2,060

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL – unaudited

(in thousands)


	Common Units					Accumulated Other Comprehensive Income (loss)			Total

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

Unit-based compensation		49		1,406			—			1,406
Distributions paid				(40,418	)		—			(40,418	)
Net income (loss)				(110,344	)		—			(110,344	)
Other comprehensive income (loss)				—			(147	)		(147	)


Balance at March 31, 2012		79,082	$	431,605		$	596		$	432,201


	Common 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		4		4,930			—		—			4,930
Costs associated with merger		—		(10,997	)		—		—			(10,997	)
Units issued to acquire non-controlling interests		32,665		204,537			250		(204,787	)		—
Distributions paid				(15,239	)		—		(15,394	)		(30,633	)
Net income (loss)				8,175			—		(664	)		7,511
Other comprehensive income (loss)							189		—			189


Balance at March 31, 2011		70,962	$	405,052		$	598	$	—		$	405,650

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

March 31, 2012

1.	Organization and Basis of Presentation

Penn Virginia Resource Partners, L.P. is a publicly traded Delaware master limited partnership, the limited partner units representing limited partner interests which 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 Penn Virginia Resource 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 two business segments: (i) natural gas midstream and (ii) coal and natural resource management.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma, Texas and Pennsylvania. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we are a partner in several joint ventures that gather and transport natural gas and water. We own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are located in Illinois, Indiana, Kentucky, New Mexico, Tennessee, Virginia and West Virginia. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

In accordance with accounting standards, which we adopted during the three months ended March 31, 2012, when reviewing long-lived assets to be held and used, including related tangible assets, we have adopted the approach to review qualitative factors (such as, macroeconomic conditions, industry and market considerations, overall financial performance, etc.) 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 its carrying amount, including goodwill if any. As a result, we recognize an impairment loss when the carrying amount of an asset exceeds the sum of the undiscounted estimated 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.

During the three months ended March 31, 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. Management 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 no subsequent events have occurred that would require recognition in the Consolidated Financial Statements, but disclosure is required in the Notes to the Consolidated Financial Statements. See Note 11 to the Consolidated Financial Statements.

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

2.	Impairment

During the three months ended March 31, 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets in the natural gas 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 determined using the income approach and discounting the estimated cash flows for the assets. This is a nonrecurring fair value measurement (see Footnote 3. 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 less than 1% of our consolidated total revenues for the three months ended March 31, 2012 and 2011.

3.	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 March 31, 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 March 31, 2012, the fair value of our fixed-rate debt was $304.5 million.

Recurring Fair Value Measurements

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


				Fair Value Measurements at March 31, 2012, Using
Description	Fair Value Measurements at March 31, 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	$	(1,211	)	$	—	$	(1,211	)	$	—
Commodity derivative liabilities – current		(12,288	)		—		(12,288	)		—

Total	$	(13,499	)	$	—	$	(13,499	)	$	—


				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 derivatives 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 based on 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 the 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

In connection with our review of tangible and related intangible assets, if there is an indication of impairment and the estimated undiscounted 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.

4.	Derivative Instruments

Natural Gas Midstream Segment 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 March 31, 2012 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:


	Average Volume				Weighted Average Price				Fair Value at
	Per Day		Swap Price		Put		Call		March 31, 2012

NGL – natural gasoline collar		(gallons)				(per gallon)
Second quarter 2012 through fourth quarter 2012		54,000			$	1.75	$	2.02	$	(5,706	)

Crude oil swap		(barrels)		(per barrel)
Second quarter 2012 through fourth quarter 2012		600	$	88.62						(2,595	)

Natural gas purchase swap		(MMBtu)		(MMBtu)
Second quarter 2012 through fourth quarter 2012		4,000	$	5.195						(2,940	)

Settlements to be paid in subsequent period										(1,047	)

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 March 31, 2012:


	Notional Amounts		Swap Interest Rates (1)					Fair Value at
Term	(in millions)		Pay			Receive		March 31, 2012

April 2012 – December 2012	$	100.0		2.09	%		LIBOR	$	(1,211	)

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

We reported a (i) net derivative liability of $1.2 million at March 31, 2012 and (ii) gain in accumulated other comprehensive income (“AOCI”) of $0.6 million as of March 31, 2012 related to the Interest Rate Swaps. In connection with periodic settlements and related reclassification of other comprehensive income, we recognized $0.1 million of net hedging losses on the Interest Rate Swaps in the derivatives line on the Consolidated Statements of Operations during the three months ended March 31, 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	Three Months Ended March 31,
	in statement of operations	2012			2011
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivatives	$	(22	)	$	(382	)
Commodity contracts	Derivatives		(4,929	)		(19,379	)


Total decrease in net income or increase in net loss resulting from derivatives		$	(4,951	)	$	(19,761	)


Realized and unrealized derivative impact:
Cash paid for commodity and interest rate contract settlements	Derivatives	$	(3,641	)	$	(4,858	)
Unrealized derivative losses	Derivatives		(1,310	)		(14,903	)

Total decrease in net income or increase in net loss resulting from derivatives		$	(4,951	)	$	(19,761	)

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 March 31, 2012				Fair Values as of December 31, 2011
		Derivative		Derivative		Derivative		Derivative
	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	1,211	$	—	$	1,433
Commodity contracts	Derivative assets/liabilities – current		—		12,288		—		10,609

Total derivatives not designated as hedging instruments		$	—	$	13,499	$	—	$	12,042


Total fair value of derivative instruments		$	—	$	13,499	$	—	$	12,042

As of March 31, 2012, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of March 31, 2012, we did not own derivative instruments containing credit risk contingencies.

5.	Equity Investments

In accordance with the equity method of accounting, we recognized earnings from all equity investments in the aggregate of $1.0 million and $1.6 million for the three months ended March 31, 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 $0.2 million and $4.8 million for the three months ended March 31, 2012 and 2011. 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.

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:


	February 29, 2012		November 30, 2011
Current assets	$	28,731	$	24,527
Noncurrent assets	$	224,927	$	217,517
Current liabilities	$	11,100	$	14,861
Noncurrent liabilities	$	2,665	$	2,571

	Three Months Ended February 29,
	2012		2011
Revenues	$	12,706	$	14,823
Expenses	$	9,045	$	8,235
Net income	$	3,661	$	6,588

6.	Long-term Debt

Revolver

As of March 31, 2012, net of outstanding indebtedness of $617.0 million and letters of credit of $2.5 million, we had remaining borrowing capacity of $380.5 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the first quarter of 2012 was approximately 2.9%. We do not have a public rating for the Revolver. As of March 31, 2012, we were in compliance with all covenants under the Revolver.

7.	Partners’ Capital and Distributions

As of March 31, 2012, partners’ capital consisted of 79.1 million common units.

Net Income (Loss) per Limited Partner Unit

Basic net income (loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner and vested deferred common units outstanding during the period. Diluted net income

(loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner and vested deferred common units outstanding during the period and, when dilutive, phantom units. For the three months ended March 31, 2011, weighted average awards of 32 thousand phantom units were excluded from the diluted net income per limited partner unit calculation because the inclusion of these phantom units would have had an antidilutive effect. No phantom unit awards were excluded from the net loss per limited partner unit calculation for the three months ended March 31, 2012.

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


	Three Months Ended March 31,
	2012			2011

Net income (loss)	$	(110,344	)	$	7,511
Net loss attributable to noncontrolling interests, pre-merger		—			664

Net income (loss) attributable to Penn Virginia Resource Partners, L.P.	$	(110,344	)	$	8,175
Adjustments:
Distributions to participating securities		(131	)		(82	)
Participating securities’ allocable share of net income		349			(30	)

Net income (loss) allocable to limited partners, basic	$	(110,126	)	$	8,063

Participating securities’ allocable share of net income (loss)		(349	)		30
Participating securities’ earnings reallocated to unvested securities		349			(30	)

Net income (loss) allocable to limited partners, diluted	$	(110,126	)	$	8,063


Weighted average limited partner units, basic		79,301			46,426
Effect of dilutive securities:
Phantom units		39			—

Weighted average limited partner units, diluted		79,340			46,426


Net income (loss) per limited partner unit, basic	$	(1.39	)	$	0.17
Net income (loss) per limited partner unit, diluted	$	(1.39	)	$	0.17

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to 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 and our general partner for any one or more of the next four quarters.

The following table reflects the allocation of total cash distributions paid by us during the periods presented:


	Three Months Ended March 31,
	2012		2011
Limited partners	$	40,307	$	30,587
Phantom units		111		46


Total cash distribution paid during period	$	40,418	$	30,633

On May 14, 2012, we will pay a $0.52 per unit quarterly distribution to unitholders of record on May 8, 2012.

8.	Unit-Based Compensation

The Penn Virginia Resource 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 three months ended March 31, 2012, we granted 237 thousand phantom units at a weighted average grant-date fair value of $24.13 including 124 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 phantom units vested during the first quarter. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units.

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 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 March 31,
	2012		2011
Phantom units	$	1,888	$	530
Director deferred and common units		150		291

	$	2,038	$	821

9.	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.

Environmental Compliance

As of March 31, 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 and natural gas 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

For the three months ended March 31, 2012, four of our natural gas midstream segment customers accounted for $105.2 million, or an aggregate of 43% of our total consolidated revenues. At March 31, 2012, 36% of our consolidated accounts receivable related to these customers.

10.

Segment Information

Our reportable segments are as follows:

•

Natural Gas Midstream — Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. In addition, we own member interests in joint ventures that gather and transport natural gas and water.

•

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 fee-based coal-related infrastructure facilities and collecting oil and gas royalties.

The following tables present a summary of certain financial information relating to our segments for the periods presented:


	Revenues				Operating income (loss)
	Three Months Ended March 31,				Three Months Ended March 31,
	2012		2011		2012			2011

Natural gas midstream	$	207,055	$	208,099	$	(118,228	)	$	10,507
Coal and natural resource management		39,362		45,428		22,536			27,478

Totals	$	246,417	$	253,527	$	(95,692	)	$	37,985

Interest expense						(9,817	)		(10,850	)
Derivatives						(4,951	)		(19,761	)
Other						116			137

Net income (loss)					$	(110,344	)	$	7,511


	Additions to property and equipment				Depreciation, depletion & amortization
	Three Months Ended March 31,				Three Months Ended March 31,
	2012		2011		2012		2011

Natural gas midstream	$	75,323	$	37,067	$	15,667	$	11,924
Coal and natural resource management		246		95,600		8,186		9,320

Totals	$	75,569	$	132,667	$	23,853	$	21,244


	Total assets at
	March 31,		December 31,
	2012		2011

Natural gas midstream	$	831,264	$	910,795
Coal and natural resource management		679,919		683,197

Totals	$	1,511,183	$	1,593,992

11.

Subsequent Event

Chief Acquisition

On April 9, 2012, we entered into a membership interest purchase and sale agreement (“Purchase Agreement”) to acquire Chief Gathering LLC (“Chief Gathering”) from Chief E&D Holdings LP (“Chief Holdings”), for a base purchase price of $1.0 billion, payable in a combination of $800 million in cash and $200 million in a new class of limited partner interests in us (“Special Units”) subject to adjustment as provided in the Purchase Agreement. The Special Units are substantially similar to our common units, except that the Special Units, to be issued to Chief Holdings, will neither pay nor accrue distributions for six consecutive quarterly distributions commencing with the first quarterly distribution whose record date occurs after the date of the closing of the Purchase Agreement. We expect to finance the purchase through a combination of committed equity and debt. The transaction is expected to close in the second quarter of 2012, subject to regulatory clearances and other customary closing conditions.

Chief Gathering owns and operates 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, when closed, will result in a major expansion of PVR’s pipeline systems in the Marcellus Shale region.

On April 9, 2012, we entered into (i) a Class B unit purchase agreement with Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. (the “Riverstone Investor”) to sell $400.0 million of Class B Units, representing a new class of limited partner interests in us (the “Class B Units”), in a private placement to the Riverstone Investor, and (ii) a common unit purchase agreement with the purchasers named therein to sell $180.0 million of our common units in a private placement to such purchasers (the “PIPE Transaction”). We will use the proceeds from the sale of the Class B Units and the common units in the PIPE Transaction to fund a portion of the cash purchase price for the Chief acquisition. Issuance of the Class B Units and the PIPE Transaction are subject to the closing of the Chief acquisition.

Amendment to Revolver

In connection with the Chief acquisition, we, together with our wholly owned subsidiary, PVR Finco LLC, and certain of our other affiliates, entered into an amendment to the Revolver, or the Revolver Amendment; certain provisions of which were effective on April 23, 2012 and certain provisions of which will be effective upon the consummation of the Chief acquisition to, among other things, to allow for certain modifications to facilitate the Chief acquisition. Specifically, the Revolver Amendment modifies certain covenants in our Revolver, including, but not limited to, covenants relating to permitted indebtedness, permitted liens and certain financial covenants, in order to permit us to obtain a bridge loan commitment and to incur other indebtedness in order to finance the Chief acquisition.

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

•

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 coal lessees and natural gas midstream 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 coal and natural resource management or natural gas midstream businesses;

•

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

•

our ability to successfully complete the acquisition of Chief Gathering LLC, complete the construction and 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;

•

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

•

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 our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business;

•

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

•

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;

•

uncertainties relating to 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;

•

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

•

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 Penn Virginia Resource 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.

Key Developments

During the three months ended March 31, 2012, the following general business developments and corporate actions had an impact, or will have impact, on our results of operations. A discussion of these key developments follows:

Chief Acquisition

We expect to finance the cash portion of the purchase price for the Chief acquisition through a combination of committed equity and debt. On April 9, 2012, we entered into (i) a Class B unit purchase agreement with Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. (the “Riverstone Investor”) to sell $400.0 million of Class B Units, representing a new class of limited partner interests in us (the “Class B Units”), in a private placement to the Riverstone Investor, and (ii) a common unit purchase agreement with the purchasers named therein to sell $180.0 million of our common units in a private placement to such purchasers (the “PIPE Transaction”). We will use the proceeds from the sale of the Class B Units and the common units in the PIPE Transaction to fund a portion of the cash purchase price for the Chief acquisition. Issuance of the Class B Units and the PIPE Transaction are subject to the closing of the Chief acquisition.

PVR Midstream Marcellus Shale Construction

During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. We have completed the initial Wyoming County system which is currently averaging 142 MMcfd. The current Wyoming system has nine miles of 12 inch pipeline connected to 10 wells. Ongoing Wyoming County construction activities relate to constructing system extensions to service local producers. The initial phase of the Lycoming County system was placed into service in February of 2011, with the Phase II segment completed in February of 2012. The system currently gathers around 100 MMcfd. Construction activities are currently ongoing related to connecting existing gathering pipelines. Currently, 38 wells are tied to the Lycoming system and are flowing gas, 37 wells have pipeline connections and are waiting on well connections and completions, and 6 wells are complete and ready to flow, upon completion of pipeline connections to the well pads. The current Lycoming system has 18.0 miles of 30 inch trunk line and 17.8 miles of gathering pipelines ranging in size from 8 to 16 inches. We anticipate beginning construction on phase III of the Lycoming system in the second quarter of 2012. These Wyoming and Lycoming County systems are experiencing ongoing expansions for the foreseeable future.

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 2102.

Panhandle

Our Panhandle system volumes continue to increase as development in the Granite-wash region continues at a strong pace. With the completion of the first expansion at our Antelope Hills facility, we are now able to process all of the volumes gathered on our Panhandle system. We expect to complete an additional expansion by the end of the second quarter 2012, and we anticipate being able to process all of our Panhandle system supply without any processing capacity constraints through the remainder of 2012. We did experience some downstream NGL constraints during the first quarter which arose due to weather and force majeure events; however, those issues were fully remedied.

North Texas Impairment

During the three months ended March 31, 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets in the natural gas 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 less than 1% of our consolidated total revenues for the three months ended March 31, 2012 and 2011. The Partnership does not expect to incur any significant cash expenditures in the next several years with respect to these natural gas gathering assets as a result of the impairment.

2012 Commodity Prices

The average commodity prices for crude oil and the heavier natural gas liquids, or NGLs (such as butane and natural gasoline) for the first quarter of 2012 increased from levels experienced in the first quarter of 2011, while natural gas prices and the lighter NGLs (such as ethane and propane, which make up the larger percentage of NGLs extracted from the processed natural gas) decreased for the comparable periods. The increase in crude oil prices reflect changes in global oil supplies, as significant unplanned disruptions in production from countries that are not members of the Organization of the Petroleum Exporting Countries (OPEC) have occurred. Market demands have decreased for natural gas and propane because of excess storage caused by the mild winter. Heavy NGL prices continued to hold firm as they continue to keep pace with crude oil prices. Additionally, the current infrastructure is inadequate to move the national growth in NGL production to market. There is currently a regional oversupply of NGLs at Conway, Kansas. Natural gas processing, fractionation and pipeline projects currently under development should be adequate to meet production growth in the future. Several announced petrochemical expansion projects should help absorb the incremental ethane supply as well, which should lead to a rebound in prices. These changes in commodity pricing caused us to realize a slightly lower fractionation, or frac, spread. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are 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 is 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 that expire at the end of 2012.

Coal royalties, which accounted for 84% of the coal and natural resource management segment revenues for the three months ended March 31, 2012 and 86% for the same period in 2011, were lower as compared to 2011. The decrease was attributed to decreased production offset by higher realized coal royalty per ton primarily in the Central Appalachia region. A ramp up in both thermal and metallurgical coal pricing, as well as production, caused 2011 to be a strong year. We have seen a decrease in coal prices and production during the first quarter of 2012 (relative to the fourth quarter of 2011) related primarily to changes in market demand due to a mild winter and low natural gas prices. Both reasons have become variables as to why coal stock piles have risen in the industry and have brought prices down. Despite the softening of coal prices, the coal prices received by our lessees during the first quarter of 2012 were still higher than what they received in the first quarter of 2011.

Results of Operations

Consolidated Review

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


	Three Months Ended March 31,
	2012			2011
Revenues	$	246,417		$	253,527
Expenses		(342,109	)		(215,542	)

Operating income (loss)		(95,692	)		37,985
Other income (expense)		(14,652	)		(30,474	)

Net income (loss)		(110,344	)		7,511
Net loss attributable to noncontrolling interests		—			664

Net income (loss) attributable to Penn Virginia Resource Partners, L.P.	$	(110,344	)	$	8,175

Natural Gas Midstream Segment

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011

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


										% Change
	Three Months Ended March 31,						Favorable			Favorable
	2012			2011			(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Residue gas	$	74,627		$	91,978		$	(17,351	)		(19	%)
Natural gas liquids		104,276			98,828			5,448			6	%
Condensate		13,518			10,014			3,504			35	%
Gathering, processing and transportation fees		13,855			5,461			8,394			154	%

Total natural gas midstream revenues		206,276			206,281			(5	)		(0	%)
Equity earnings in equity investments		314			1,030			(716	)		(70	%)
Producer services and other		465			788			(323	)		(41	%)

Total revenues		207,055			208,099			(1,044	)		(1	%)


Expenses
Cost of gas purchased		165,464			170,255			4,791			3	%
Operating		12,125			9,389			(2,736	)		(29	%)
General and administrative		7,182			6,024			(1,158	)		(19	%)
Impairments		124,845			—			(124,845	)		(100	%)
Depreciation and amortization		15,667			11,924			(3,743	)		(31	%)

Total operating expenses		325,283			197,592			(127,691	)		(65	%)


Operating income (loss)	$	(118,228	)	$	10,507		$	(128,735	)		(1225	%)


Operating Statistics
Daily throughput volumes (MMcfd)		653			420			233			55	%

Gross margin	$	40,812		$	36,026		$	4,786			13	%
Cash impact of derivatives		(3,250	)		(2,982	)		(268	)		9	%

Gross margin, adjusted for impact of derivatives	$	37,562		$	33,044		$	4,518			14	%

Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our cost of gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. 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 gross margin increase was a result of higher system throughput volumes in both the Marcellus and Panhandle systems, and higher processed volumes on the Panhandle system. The Marcellus Shale system’s average quarterly throughput volumes increased from 39 MMcfd during the first quarter of 2011 up to 211 MMcfd during the first quarter of 2012. Offsetting the higher gross margin on the Marcellus system were the results of operations on the Panhandle system. The higher throughput and processed volumes on the Panhandle system were more than offset by lower NGL and natural gas prices received for processed gas. We also experienced some downstream NGL constraints during the first quarter which arose due to weather and force majeure events; however, those issues appear to be fully remedied.

We generated a portion of our gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and natural gas purchased when it is opportunistic. Midstream gross margin, including the cash impact of existing midstream derivatives, was $37.6 million compared to $33.0 million. This $4.6 million increase was primarily due to the increased system volumes and related fee-based gathering revenues earned on the Marcellus system.

Equity earnings of our joint ventures were lower due to declining natural gas prices and the related effects on volumes. Producer services and other decreased due to the expiration of a significant master service agreement in 2011.

Expenses

Operating expenses increased due to prior and current years’ expansion projects and acquisitions. The related costs of these facilities included increased compressor rentals, utilities, supplies and property taxes.

General and administrative expenses increased as a result of costs to establish the Marcellus system management team and increased equity compensation.

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 expenses increased primarily due to acquisitions and capital expansions on the Marcellus Shale and Panhandle systems.

Coal and Natural Resource Management Segment

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 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 March 31,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	33,159	$	38,991	$	(5,832	)		(15	%)
Coal services		1,238		2,310		(1,072	)		(46	%)
Timber		1,520		1,109		411			37	%
Oil and gas royalty		683		793		(110	)		(14	%)
Other		2,762		2,225		537			24	%

Total revenues		39,362		45,428		(6,066	)		(13	%)


Expenses
Operating		3,778		3,684		(94	)		(3	%)
General and administrative		4,862		4,946		84			2	%
Depreciation, depletion and amortization		8,186		9,320		1,134			12	%

Total expenses		16,826		17,950		1,124			6	%


Operating income	$	22,536	$	27,478	$	(4,942	)		(18	%)


Other data

Coal royalty tons by region
Central Appalachia		4,068		5,070		(1,002	)		(20	%)
Northern Appalachia		798		1,146		(348	)		(30	%)
Illinois Basin		1,137		1,271		(134	)		(11	%)
San Juan Basin		2,102		2,410		(308	)		(13	%)

Total tons		8,105		9,897		(1,792	)		(18	%)


Coal royalties revenues by region
Central Appalachia	$	23,782	$	27,966	$	(4,184	)		(15	%)
Northern Appalachia		2,100		2,363		(263	)		(11	%)
Illinois Basin		2,379		3,213		(834	)		(26	%)
San Juan Basin		4,898		5,449		(551	)		(10	%)

Total royalties	$	33,159	$	38,991	$	(5,832	)		(15	%)


Coal royalties per ton by region ($/ton)
Central Appalachia	$	5.85	$	5.52	$	0.33			6	%
Northern Appalachia		2.63		2.06		0.57			28	%
Illinois Basin		2.09		2.53		(0.44	)		(17	%)
San Juan Basin		2.33		2.26		0.07			3	%

Average royalties per ton	$	4.09	$	3.94	$	0.15			4	%

Revenues

Coal royalties, which accounted for 84% of the coal and natural resource management segment revenues for the three months ended March 31, 2012 and 86% for the same period in 2011, were lower as compared to 2011. The decrease was attributed to decreased production partially offset by higher realized coal royalty per ton primarily in the Central and Northern Appalachia regions. A ramp up in both thermal and metallurgical coal pricing, as well as production, caused 2011 to be a strong year. We have seen a decrease in both coal prices and production during the first quarter of 2012 (relative to the fourth quarter of 2011) related primarily to changes in market demand due to a mild winter and low natural gas prices. Both reasons have become variables as to why coal stock piles have risen in the industry and have brought prices down. However, coal prices received by our lessees during the first quarter of 2012 were still higher than what they received in the first quarter of 2011.

Coal royalties per ton increased in all regions, except for the Illinois Basin, for the first quarter of 2012 compared to the same quarter of last year. The reduced realized royalty rate in the Illinois Basin is due to contractual changes in royalties we receive on some properties in this region.

Consistent with the decrease in coal production, coal services revenues also decreased. Timber revenues have increased due to the mild winter, which provided for ideal harvest weather. Other revenues in the first quarter of 2012 have increased due to minimum royalty forfeitures. Based upon lease contracts, which vary by lessee, lessees paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred after the exhaustion of that time period, the minimum payments are recognized in earnings.

Expenses

Operating and general and administrative expenses were relatively consistent for the comparable periods. Some employee related costs for equity compensation and core hole drilling performed to true up our reserves have increased, but these increases are offset by a decrease in due diligence costs for acquisitions. In the first quarter of 2011 we incurred $0.6 million in due diligence costs related primarily to the Middle Fork acquisition.

DD&A expenses decreased for the comparative periods primarily due to the decrease in coal production and the related depletion expense.

Other

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


	Three Months Ended March 31,
	2012			2011
Operating income (loss)	$	(95,692	)	$	37,985
Other income (expense)
Interest expense		(9,817	)		(10,850	)
Derivatives		(4,951	)		(19,761	)
Other		116			137

Net income (loss)	$	(110,344	)	$	7,511

Interest Expense. Interest expense for the three months ended March 31, 2012 decreased compared to the same period in 2011. The overall net decrease is due to an increase in the amount of interest we have capitalized related to construction efforts primarily on the Marcellus Shale and Panhandle systems. An increase in Revolver interest expense partially offset the effect of capitalized interest. Revolver interest increased due to an increase in the outstanding Revolver balance.

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


	Three Months Ended March 31,
Source	2012			2011
Interest on Revolver	$	(4,824	)	$	(3,930	)
Interest on Senior Notes		(6,188	)		(6,188	)
Debt issuance costs and other		(1,049	)		(1,040	)
Capitalized interest		2,244			308

Total interest expense	$	(9,817	)	$	(10,850	)

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 March 31,
	2012			2011
Interest Rate Swap realized derivative loss	$	(391	)	$	(1,876	)
Interest Rate Swap unrealized derivative gain		222			1,683
Interest Rate Swap other comprehensive income reclass		147			(189	)
Natural gas midstream commodity realized derivative loss		(3,250	)		(2,982	)
Natural gas midstream commodity unrealized derivative loss		(1,679	)		(16,397	)

Total derivative loss	$	(4,951	)	$	(19,761	)

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. On April 9, 2012, we signed a definitive agreement to acquire Chief Gathering for a base purchase price of $1.0 billion, payable to Chief in a combination of $800.0 million in cash and $200.0 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.” 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.

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


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(110,344	)	$	7,511

Adjustments to reconcile net income to net cash provided by operating activities (summarized)		151,707			41,021
Net changes in operating assets and liabilities		3,804			6,276

Net cash provided by operating activities		45,167			54,808
Net cash used in investing activities (summarized)		(81,859	)		(131,660	)
Net cash provided by financing activities (summarized)		35,582			75,363

Net decrease in cash and cash equivalents	$	(1,110	)	$	(1,489	)

Cash Flows From Operating Activities

The overall decrease in net cash provided by operating activities in the three months ended March 31, 2012 as compared to the same period in 2011 was driven by a decrease in coal royalties and a decrease in cash distributions received from our joint ventures as well as increases in operating expense and general and administrative expense. These reductions in cash provided by operating activities were partially offset by an increase in the natural gas midstream segment’s gross margin and a decrease in derivative settlements paid.

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:


	Three Months Ended March 31,
	2012		2011
Coal and natural resource management
Acquisitions	$	136	$	97,276
Internal growth		47		—
Maintenance		3		104

Total		186		97,380


Natural gas midstream
Internal growth		69,859		21,691
Maintenance		3,094		3,075

Total		72,953		24,766


Total capital expenditures	$	73,139	$	122,146

In January 2011, we completed the acquisition of the Middle Fork properties, which added significant reserves to our coal and natural resource segment in the Central Appalachia region. Our natural gas midstream capital expenditures for the three months ended March 31, 2012 and 2011 consisted primarily of 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 three months ended March 31, 2012, we incurred net borrowings of $76.0 million to finance the construction of natural gas midstream capital expenditures. During the three months ended March 31, 2011, we incurred net borrowings of $107.0 million to fund our coal and natural resources acquisition and to finance the construction of natural gas midstream capital expenditures.

During the three months ended March 31, 2012 and 2011, we paid cash distributions to our unitholders of $40.4 million and $30.6 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 March 31,
	2012			2011
Reconciliation of GAAP “Operating income (loss)” to Non-GAAP “EBITDA”:
Operating income (loss)	$	(95,692	)	$	37,985
Impairments		124,845			—
Depreciation, depletion and amortization		23,853			21,244


EBITDA (a)	$	53,006		$	59,229


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	(110,344	)	$	7,511
Impairment		124,845			—
Depreciation, depletion and amortization		23,853			21,244
Derivative contracts:
Derivative losses included in net income		4,951			19,761
Cash payments to settle derivatives for the period		(3,641	)		(4,858	)
Equity earnings from joint ventures, net of distributions		(741	)		3,160
Maintenance capital expenditures		(3,097	)		(3,179	)
Replacement capital expenditures		(6,725	)		(6,725	)


Distributable cash flow (b)	$	29,101		$	36,914


Distribution to Partners:

Limited partners	$	40,307		$	30,587
Phantom units (c)		111			46


Total cash distribution paid during the period	$	40,418		$	30,633


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Net income as adjusted”:
Net income (loss)	$	(110,344	)	$	7,511
Impairments		124,845			—
Adjustments for derivatives:
Derivative losses included in net income		4,951			19,761
Cash payments to settle derivatives for the period		(3,641	)		(4,858	)


Net income, as adjusted (d)	$	15,811		$	22,414

(a)

EBITDA, or earnings before interest, tax and depreciation, depletion and amortization (“DD&A”), represents operating income (loss) plus DD&A, plus impairments. 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 coal and natural gas midstream 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 (loss).

(b)

Distributable cash flow represents net income (loss) plus DD&A, plus impairments, plus (minus) derivative losses (gains) included in net income (loss), 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 reserve. Distributable cash flow is a significant liquidity metric which is an indicator of our ability to generate cash flows at a level that can sustain or support the quarterly cash distributions paid to our partners. 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 (loss).

(c)	Phantom unit grants were made under our long-term incentive plan. Service based phantom units receive non forfeitable distribution rights; thus, we have presented distributions paid to phantom unit holders in our total distributions paid to Partners.

(d)

Net income (loss), as adjusted, represents net income (loss) adjusted to exclude the effects of non-cash changes in the fair value of derivatives and impairments. 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 (loss), 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 (loss).

Sources of Liquidity

Long-Term Debt

Revolver. As of March 31, 2012, net of outstanding indebtedness of $617.0 million and letters of credit of $2.5 million, we had remaining borrowing capacity of $380.5 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 three months ended March 31, 2012 was approximately 2.9%. We do not have a public rating for the Revolver. As of March 31, 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 March 31, 2012:

Notional Amounts

Swap Interest Rates (1)

Term

(in millions)

Pay

Receive

April 2012 – December 2012

100.0

2.09

LIBOR

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

After considering the applicable margin of 2.25% in effect as of March 31, 2012, the total interest rate on the $100.0 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 4.34% as of March 31, 2012.

Senior Notes. In April 2010, we sold $300.0 million of senior notes due on April 15, 2018 with an annual interest rate of 8.25% (the “Senior Notes”), which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. 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.

Future Capital Needs and Commitments

As of March 31, 2012, our remaining borrowing capacity under the $1.0 billion Revolver of approximately $380.5 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 $200-$250 million in internal growth capital, excluding acquisitions. In addition, we expect to incur significant additional capital expenditures related to the Chief acquisition in 2012. The majority of the 2012 internal growth capital is expected to be incurred in the natural gas midstream segment, primarily in the Marcellus Shale region. 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 if available under commercially acceptable terms.

On April 9, 2012, we signed a definitive agreement to acquire Chief Gathering for a base purchase price of $1.0 billion, payable to Chief in a combination of $800.0 million in cash and $200.0 million of a new class of limited partner interests in the Partnership, subject to adjustment as provided in the definitive agreement. The Chief Acquisition is expected to close in the second quarter of 2012, subject to regulatory clearances and other customary closing conditions. We expect to finance the cash portion of the purchase price for the Chief Acquisition through a combination of committed equity and debt. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Developments—Chief Acquisition.”

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 March 31, 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 and natural gas 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 March 31, 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 Risk

•

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 Risk

In order to manage our exposure to price risks 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. Historically, we have utilized derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our natural gas 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 risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At March 31, 2012, we reported a net commodity derivative liability related to the natural gas midstream segment of $12.3 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 March 31, 2012, we reported a net derivative loss for both commodity and Interest Rate Swaps of $5.0 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
	Per Day		Swap Price		Put		Call		March 31, 2012

NGL – natural gasoline collar		(gallons)				(per gallon)
Second quarter 2012 through fourth quarter 2012		54,000			$	1.75	$	2.02	$	(5,706	)

Crude oil swap		(barrels)		(per barrel)
Second quarter 2012 through fourth quarter 2012		600	$	88.62						(2,595	)

Natural gas purchase swap		(MMBtu)		(MMBtu)
Second quarter 2012 through fourth quarter 2012		4,000	$	5.195						(2,940	)

Settlements to be paid in subsequent period										(1,047	)

									$	(12,288	)

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 collar liability by $0.8 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 liability by $1.0 million. We estimate that a $0.10 per gallon increase or decrease in the natural gasoline (an NGL) price would increase or decrease the fair value of our natural gasoline collar liability by $1.4 million.

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 $3.3 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 $4.4 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 March 31, 2012, we had $617.0 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 April 2012 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, or 16% of our outstanding indebtedness under the Revolver as of March 31, 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 March 31, 2012 would cost us approximately $5.2 million in additional interest expense per year.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. Approximately 84%, or $75.4 million, of our consolidated accounts receivable at March 31, 2012 resulted from our natural gas midstream segment and approximately 16%, or $14.2 million, resulted from our coal and natural resource management segment. Approximately $32.4 million of the natural gas midstream segment’s receivables at March 31, 2012 related to four customers, Conoco Phillips Company, Oneok Hydrocarbon L.P., Targa Liquids Marketing and Trade and Williams NGL Marketing LLC. At March 31, 2012, 43% of our natural gas midstream segment accounts receivable and 36% of our consolidated accounts receivable related to these natural gas midstream customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to this natural gas midstream customer.

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 March 31, 2012, no receivables were collateralized, and we had a $0.3 million allowance for doubtful accounts, of which the majority related to our natural gas midstream 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 March 31, 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 March 31, 2012, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting that occurred 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 9, “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


2.1		Membership Interest Purchase and Sale Agreement by and among Chief E&D Holdings LP, as Seller, Chief Gathering LLC, the Company, PVR Marcellus Gas Gathering LLC, as Buyer, and Penn Virginia Resource Partners, L.P., as Issuer, dated April 9, 2012 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on April 12, 2012).

10.1		Class B Unit Purchase Agreement, dated April 9, 2012, by and among Penn Virginia Resource Partners, L.P., Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on April 12, 2012).

10.2		Common Unit Purchase Agreement, dated April 9, 2012, by and among Penn Virginia Resource Partners, L.P. and the purchasers named therein (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on April 12, 2012).

10.3		Second Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2012, by and among PVR Finco LLC, the guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1.2 to Registrant’s Current Report on Form 8-K filed on April 27, 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 Penn Virginia Resource Partners L.P. for the quarter ended March 31, 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.

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.


	PENN VIRGINIA RESOURCE PARTNERS, L.P.

	By:	PENN VIRGINIA RESOURCE GP, LLC

Date: May 7, 2012	By:	/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer

Date: May 7, 2012	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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