PVR PARTNERS, L. P. - FORM 8-K - EX-99.1 - REVISED PART I, ITEM 1: FINANCIAL STATEMENTS

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Exhibit 99.1

The information provided in this Exhibit is presented only in connection with the reporting change described in the accompanying Current Report on Form 8-K. This information does not reflect events occurring after May 7m 2012, the date we filed our 2012 Form 10-Q, and does not modify or update the disclosures therein in any way, other than as required to reflect the change in segments as described in the Form 8-K and set forth in Exhibits 99.1 attached thereto. You should therefore read this information in conjunction with the 2012 Form 10-Q and with our reports filed with the Securities and Exchange Commission after May 7, 2012.

Forward-Looking Statements

Certain statements contained in this Current Report on Form 8-K 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 Eastern Midstream and Midcontinent 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 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 Eastern Midstream and Midcontinent Midstream businesses;

•

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 and permissible levels of mining runoff;

•

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

•

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

•

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

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

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	$	74,627		$	91,978
Natural gas liquids		117,794			108,842
Gathering and transportation		13,855			5,461
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. (NYSE: PVR) is 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. We currently conduct operations in three business segments which are as follows:

•

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

•

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

•

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

In accordance with accounting standards, 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, 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 Midcontinent Midstream segment located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). The gathering lines and customer contracts were written down to their fair value 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 in our Midcontinent Midstream segment 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

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 Per Day			Swap Price			Weighted Average Price				Fair Value at March 31, 2012
	Average Volume Per Day			Swap Price			Put		Call		Fair Value at 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 March 31, 2012
Term	(in millions)		Pay			Receive		Fair Value at 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 in statement of operations	Three Months Ended March 31,
		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 Eastern Midstream and Midcontinent Midstream businesses and our Coal and Natural Resource Management business. 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 Midcontinent 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 operating segments represent components of our business about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our Eastern Midstream and Midcontinent Midstream natural gas operations and Coal and Natural Resource Management operations. Accordingly, our reportable segments are as follows:

•

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


	Eastern Midstream		Midcontinent Midstream			Coal and Natural Resource Management		Consolidated
For the three months ended March 31, 2012
Revenues	$	11,473	$	195,582		$	39,362	$	246,417
Cost of midstream gas purchased		—		165,464			—		165,464
Operating costs and expenses		1,512		17,795			8,640		27,947
Impairments		—		124,845			—		124,845
Depreciation, depletion & amortization		2,061		13,606			8,186		23,853

Operating income	$	7,900	$	(126,128	)	$	22,536	$	(95,692	)

Interest expense									(9,817	)
Derivatives									(4,951	)
Other									116

Net income								$	(110,344	)

Additions to property and equipment	$	31,284	$	44,039		$	246	$	75,569

For the three months ended March 31, 2011
Revenues	$	3,020	$	205,079		$	45,428	$	253,527
Cost of midstream gas purchased		—		170,255			—		170,255
Operating costs and expenses		236		15,177			8,630		24,043
Depreciation, depletion & amortization		353		11,571			9,320		21,244

Operating income	$	2,431	$	8,076		$	27,478	$	37,985

Interest expense									(10,850	)
Derivatives									(19,761	)
Other									137
Net income								$	7,511

Additions to property and equipment	$	23,912	$	13,155		$	95,600	$	132,667


	Total assets at
	March 31,		December 31,
	2012		2012
Eastern Midstream	$	204,217	$	174,444
Midcontinent Midstream		627,047		736,351
Coal and Natural Resource Management		679,919		683,197

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

11. Subsequent Events

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.

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.

On May 17, 2012 the Chief Acquisition was completed with us paying $850.0 million in cash and $191.3 million of preliminary fair value Special Units. The acquisition was accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price has been allocated to the current assets and liabilities and the tangible, intangible and goodwill assets acquired. The purchase price allocation for the Chief Acquisition is preliminary and has not been finalized. We need to complete certain post-closing adjustments with the seller and the appraisal of the assets acquired. Fair values have been developed using recognized business valuation techniques and are subject to change pending final valuation analysis.

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 were 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.

Bridge Loans

In April 2012, in connection with the proposed Chief Acquisition, we obtained a commitment from commercial banks for senior unsecured bridge loans in an aggregate amount up to $220 million (the “Bridge Loans”). The commitment expired in May 2012 upon issuance of the 8.375% Senior Notes.

Senior Notes

On May, 17, 2012, we completed the issuance of $600 million of senior notes in a private placement. These notes were priced at 100% of the principal amount and bear interest at a rate of 8.375% per year, due June 1, 2020. They are fully and unconditionally guaranteed by PVR’s existing and future domestic restricted subsidiaries, subject to certain exceptions. Approximately $250 million of the proceeds from the senior notes offering was used in connection with the financing of the Chief Acquisition, and the remainder was used to pay down a portion of the outstanding borrowings under PVR’s Revolver.

Sale of Crossroads System

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for cash proceeds of $63 million. The Crossroads system, located in the Midcontinent Midstream segment in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline.

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. We currently conduct operations in three business segments which are as follows:

•

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:

Eastern Midstream Segment

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 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.

Midcontinent Midstream Segment

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 Midcontinent Midstream segment located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). The impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented less than 1% of our consolidated total revenues for the three months ended March 31, 2012 and 2011.

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 Eastern Midstream and Midcontinent Midstream segments 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

Eastern 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 Eastern Midstream segment and the percentage change for the periods presented:


	Three Months Ended March 31,				Favorable			% Change Favorable
	2012		2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Gathering and transportation fees	$	11,311	$	3,020	$	8,291			275	%
Other		162		—		162			N/A

Total revenues		11,473		3,020		8,453			280	%

Expenses
Operating		898		236		(662	)		(281	%)
General and administrative		614		—		(614	)		N/A
Depreciation and amortization		2,061		353		(1,708	)		(484	%)

Total operating expenses		3,573		589		(2,984	)		(507	%)

Operating income (loss)	$	7,900	$	2,431	$	5,469			225	%

Operating Statistics
Daily throughput volumes (MMcfd)		211		39		172			441	%

Revenues

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.

Expenses

Operating expenses increased due to our expansion projects. The related costs of these facilities included increased costs of labor, supplies and property tax.

General and administrative expenses increased due to the establishment of a management team and an office in Williamsport, Pennsylvania. Labor and related benefit costs accounted for the majority of the increase.

Depreciation and amortization expenses increased primarily due to capital expansions.

Midcontinent 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 Midcontinent Midstream segment and the percentage change for the periods presented:


	Three Months Ended March 31,					Favorable			% Change
	2012			2011		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	74,627		$	91,978	$	(17,351	)		(19	%)
Natural gas liquids		117,794			108,842		8,952			8	%
Gathering and transportation fees		2,544			2,441		103			4	%
Other		617			1,818		(1,201	)		(66	%)

Total revenues		195,582			205,079		(9,497	)		(5	%)

Expenses
Cost of gas purchased		165,464			170,255		4,791			3	%
Operating		11,227			9,153		(2,074	)		(23	%)
General and administrative		6,568			6,024		(544	)		(9	%)
Impairments		124,845			—		(124,845	)		(100	%)
Depreciation and amortization		13,606			11,571		(2,035	)		(18	%)

Total operating expenses		321,710			197,003		(124,707	)		(63	%)

Operating income (loss)	$	(126,128	)	$	8,076	$	(134,204	)		(1662	%)

Operating Statistics
Daily throughput volumes (MMcfd)		442			381		61			16	%

Revenues

Revenues primarily included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, and gathering and transportation fees. We process gas under three general types of contracts (gas purchase/keep whole contracts, percentage-of-proceeds contracts, and fee-based arrangements). These contracts are more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010. New gas volumes being added to our Panhandle system are primarily under percentage of proceeds contracts. The result of this is a relative volumetric decrease in the higher-risk, higher-margin gas purchase/keep whole contracts, meaning that we are sharing more of the processing margin with our producers in this region.

Natural gas revenues decreased primarily due to prices. The average New York Mercantile Exchange (“NYMEX”) natural gas spot price decreased 34%, from $4.13 in the first quarter of 2011 compared to $2.74 in the comparable period of 2012.

Natural gas liquids (“NGLs”) and condensate revenues increased primarily due to the increased processed volumes offset by a decrease in NGL prices. The daily throughput volumes on our system increased by 16%,which correlated to increased processed NGL volumes. Our average realized price received for a hypothetical barrel of NGLs processed in Conway, Kanasas in the 1Q of 2012 was $41.89 compared to $48.37 for the comparable period of 2011. NGL and condensate prices can fluctuate significantly based on market conditions in certain areas. In order to obtain favorable pricing, we sell our NGLs and condensate to several customers in multiple markets, including Mont Belvieu.

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

Expenses

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The amounts we pay producers fluctuate each period due to the volumes related to each type of processing contract. Recently, we have entered into more fee based contracts to reduce our commodity exposure. The average NYMEX natural gas spot price decreased 34%, from $4.13 in the second quarter of 2011 compared to $2.74 in the comparable period of 2012. The decrease was offset by an increase in NGL volumes.

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

General and administrative expenses increased as a result of 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

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 Eastern Midstream and Midcontinent Midstream segments. 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	)
Commodity realized derivative loss		(3,250	)		(2,982	)
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 Eastern Midstream segments operating income 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,
	2112		2011
Eastern Midstream
Internal growth	$	26,713	$	12,870
Maintenance		—		148

Total		26,713		13,018

Midcontinent Midstream
Internal growth	$	43,146	$	8,821
Maintenance		3,094		2,927

Total		46,240		11,748

Coal and Natural Resource Management
Acquisitions	$	136	$	97,276
Internal growth		47		—
Maintenance		3		104

Total		186		97,380

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 Management 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 Eastern Midstream and Midcontinent Midstream segments.

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 Eastern Midstream and Midcontinent Midstream segments. During the three months ended March 31, 2011, we incurred net borrowings of $107.0 million to fund our Coal and Natural Resource Management acquisition and to finance the construction of our Eastern Midstream and Midcontinent Midstream segments.

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 December 31,
	2012			2011
Reconciliation of Non-GAAP “Segment Adjusted EBITDA” to GAAP “Net income (loss)”:
Segment Adjusted EBITDA (a):
Eastern Midstream	$	9,961		$	2,784
Midcontinent Midstream		12,323			19,647
Coal and Natural Resource Management		30,722			36,798

Total segment Adjusted EBITDA	$	53,006		$	59,229
Adjustments to reconcile total segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(23,853	)		(21,244	)
Impairment		(124,845	)		—
Interest expense		(9,817	)		(10,850	)
Derivatives		(4,951	)		(19,761	)
Other		116			137

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

Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	(110,344	)	$	7,511
Depreciation, depletion and amortization		23,853			21,244
Impairment		124,845			—
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:
Total cash distribution paid during the period	$	40,418		$	30,633

(a)

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

(b)

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

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 Eastern Midstream and Midcontinent Midstream segments, 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 Eastern Midstream and Midcontinent Midstream business and our Coal and Natural Resource Management business. 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.

PVR PARTNERS, L. P. - FORM 8-K - EX-99.1 - REVISED PART I, ITEM 1: FINANCIAL STATEMENTS - August 3, 2012

Attached files

PVR PARTNERS, L. P. Reports