PVR Partners, L. P. (PVR) 10-Q 2013 Q1 Quarterly report

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, 2013

or

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

For the transition period from                     to                    

Commission File Number: 1-16735

PVR PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	23-3087517
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Three Radnor Corporate Center, Suite 301

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.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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 12, 2013, 95,713,267 common units, 22,782,740 Class B Units, and 10,346,257 Special Units representing limited partner interests were outstanding.

		Page
PART I. Financial Information
Item 1.	Financial Statements
	Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012		1
	Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2013 and 2012		1
	Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012		2
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012		3
	Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2013 and 2012		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		22
Item 4.	Controls and Procedures		24
PART II. Other Information
Item 1.	Legal Proceedings		24
Item 1A.	Risk Factors		24
Item 6.	Exhibits		24

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per unit data)

	Three Months Ended March 31,
	2013			2012
Revenues
Natural gas	$	87,714		$	74,627
Natural gas liquids		100,508			117,794
Gathering fees		22,916			7,463
Trunkline fees		21,101			6,392
Coal royalties		22,951			33,159
Other		8,221			6,982
Total revenues		263,411			246,417
Expenses
Cost of gas purchased		158,208			165,464
Operating		15,370			15,903
General and administrative		13,785			12,044
Impairments		—			124,845
Depreciation, depletion and amortization		44,786			23,853
Total expenses		232,149			342,109
Operating income (loss)		31,262			(95,692	)
Other income (expense)
Interest expense		(23,678	)		(9,817	)
Derivatives		(441	)		(4,951	)
Other		94			116
Net income (loss)	$	7,237		$	(110,344	)
Earnings (loss) per common unit, basic and diluted	$	(0.17	)	$	(1.39	)
Weighted average number of common units outstanding, basic		95,906			79,301
Weighted average number of common units outstanding, diluted		95,906			79,340

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – unaudited

(in thousands)

	Three Months Ended March 31,
	2013		2012
Net income (loss)	$	7,237	$	(110,344	)
Reclassification adjustment for derivative activities		—		(147	)
Comprehensive income (loss)	$	7,237	$	(110,491	)

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

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PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)

	March 31, 2013			December 31, 2012
Assets
Current assets
Cash and cash equivalents	$	12,973		$	14,713
Accounts receivable, net of allowance for doubtful accounts		119,939			133,546
Assets held for sale		—			11,450
Other current assets		5,252			5,446
Total current assets		138,164			165,155
Property, plant and equipment		2,575,884			2,479,802
Accumulated depreciation, depletion and amortization		(527,652	)		(490,456	)
Net property, plant and equipment		2,048,232			1,989,346
Equity investments		106,227			97,553
Goodwill		70,283			70,283
Intangible assets (net of accumulated amortization of $49,081 and $41,452)		612,971			620,600
Other long-term assets		54,571			55,772
Total assets	$	3,030,448		$	2,998,709
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	164,492		$	197,034
Deferred income		4,908			3,788
Derivative liabilities		434			—
Total current liabilities		169,834			200,822
Deferred income		13,217			15,212
Other liabilities		20,025			20,256
Senior notes		900,000			900,000
Revolving credit facility		700,000			590,000
Partners’ capital
Common units		624,485			671,386
Class B units		407,825			406,553
Special units		195,062			194,480
Total partners’ capital		1,227,372			1,272,419
Total liabilities and partners’ capital	$	3,030,448		$	2,998,709

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

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PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities
Net income (loss)	$	7,237		$	(110,344	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		44,786			23,853
Impairments		—			124,845
Derivative Contracts:
Total derivative losses		441			4,951
Cash payments to settle derivatives		(222	)		(3,641	)
Non-cash interest expense		1,652			1,049
Non-cash unit-based compensation		1,264			2,038
Equity earnings, net of distributions received		1,325			(741	)
Other		(2,004	)		(647	)
Changes in operating assets and liabilities
Accounts receivable		12,586			11,814
Accounts payable and accrued liabilities		12,359			(8,892	)
Deferred income		(147	)		760
Other assets and liabilities		138			122
Net cash provided by operating activities		79,415			45,167
Cash flows from investing activities
Acquisitions		(2,346	)		(196	)
Additions to property, plant and equipment		(138,446	)		(75,373	)
Joint venture capital contributions		(10,200	)		(6,600	)
Proceeds from sale of assets		11,964			—
Other		1,582			310
Net cash used in investing activities		(137,446	)		(81,859	)
Cash flows from financing activities
Distributions to partners		(52,735	)		(40,418	)
Proceeds from borrowings		135,000			86,000
Repayments of borrowings		(25,000	)		(10,000	)
Cash paid for debt issuance costs		(879	)		—
Other		(95	)		—
Net cash provided by financing activities		56,291			35,582
Net decrease in cash and cash equivalents		(1,740	)		(1,110	)
Cash and cash equivalents – beginning of period		14,713			8,640
Cash and cash equivalents – end of period	$	12,973		$	7,530
Supplemental disclosure:
Cash paid for interest	$	5,956		$	4,694

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

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PVR PARTNERS, L.P. AND SUBSIDIARIES

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

	Common Units					Class B Units				Special Units				Total
Balance at December 31, 2012		95,633	$	671,386			22,306	$	406,553		10,346	$	194,480	$	1,272,419
Unit-based compensation		80		509			—		—		—		—		509
Distributions paid		—		(52,735	)		477		—		—		—		(52,735	)
Other				(58	)		—		—		—		—		(58	)
Net income (loss)		—		5,383			—		1,272		—		582		7,237
												��
Balance at March 31, 2013		95,713	$	624,485			22,783	$	407,825		10,346	$	195,062	$	1,227,372

	Common Units					Accumulated Other Comprehensive Income (loss)			Total
Balance at December 31, 2011		79,033	$	580,961		$	743		$	581,704
Unit-based compensation		49		1406			—			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

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

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PVR PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

March 31, 2013

1. Organization and Basis of Presentation

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

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

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

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

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

During the first quarter of 2013, we adopted a new accounting standard that requires us to disclose in a single location (either on the face of the statement of operations or in the notes) the effects of reclassifications out of accumulated other comprehensive income (“AOCI”). The new disclosures requirements are effective for the first quarter 2013 and apply prospectively. All of our AOCI amounts were reclassified in 2012 and no amounts remained as of December 31, 2012. Therefore, adoption of this accounting standard does not have an effect on our financials.

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 or disclosure in these Notes.

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

2. Assets Held for Sale

As of December 31, 2012, we had $11.5 million of assets held for sale. This amount was separately stated in our Consolidated Balance Sheet in current assets. The assets represented a Midcontinent Midstream plant that we sold in the first quarter of 2013 for $12.0 million. A gain of $0.5 million was recorded in other revenues on the Consolidated Statement of Operations.

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, 2012.

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, 2013, 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

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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, 2013, the fair value of our fixed-rate debt was $947.3 million.

Recurring Fair Value Measurements

The following table summarizes the assets and liabilities measured at fair value on a recurring basis for our commodity-based derivative financial instruments:

			Fair Value Measurements at March 31, 2013, Using
Description	Fair Value Measurements at March 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity derivative liabilities - current	$	434	$	—	$	434	$	—
Total	$	434	$	—	$	434	$	—

We had no open derivative positions as of December 31, 2012; therefore, there are no recurring valuations presented as of December 31, 2012.

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

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, 2013 for commodities related to natural gas midstream revenues:

	Average Volume Per Day			Weighted Average Swap Price			Fair Value at March 31, 2013
Crude oil swap		(barrels	)		(per barrel	)
Second quarter through the fourth quarter 2013		500		$	94.80		$	(269	)
Natural gas swaps		(MMBtu	)		(per MMBtu	)
Second quarter through the fourth quarter 2013		5,500		$	3.823			(194	)
Settlements to be received in subsequent period								29

Interest Rate Swaps

During the three months ended March 31, 2013, we did not have any open Interest Rate Swap positions. Therefore, there are no fair value measurements to disclose. During the three months ended March 31, 2012 we reported a 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.

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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,
		2013			2012
Derivatives not designated as hedging instruments:
Commodity contracts	Derivatives	$	(441	)	$	(4,929	)
Interest rate contracts	Derivatives		—			(22	)
Total decrease in operating income from net loss resulting from derivatives		$	(441	)	$	(4,951	)
Realized and unrealized derivative impact:
Cash paid for commodity and interest rate contract settlements	Derivatives	$	(7	)	$	(3,641	)
Unrealized derivative losses	Derivatives		(434	)		(1,310	)
Total decrease in operating income from net loss resulting from derivatives		$	(441	)	$	(4,951	)

As of December 31, 2012, we had no open derivative positions. There were two settled but not paid commodity derivative positions in accounts payable amounting to $0.2 million. 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 new commodity hedges entered into during the first quarter of 2013:

		Fair Values as of March 31, 2013
	Balance Sheet Location	Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Commodity contracts	Derivative assets/liabilities - current	$	—	$	434
Total derivatives not designated as hedging instruments		$	—	$	434
Total fair value of derivative instruments		$	—	$	434

See Note 3, “Fair Value Measurements” for a description of how the above financial instruments are valued.

As of March 31, 2013, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of March 31, 2013, 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 $0.8 million and $1.0 million for the three months ended March 31, 2013 and 2012, with a corresponding increase in the investment. The joint ventures generally pay quarterly distributions on their cash flow. We received distributions of $2.1 million and $0.2 million for the three months ended March 31, 2013 and 2012, with a corresponding decrease in the investment. Equity earnings related to our joint venture interests are recorded in other revenues on the Consolidated Statements of Operations. The equity investments for all joint ventures are included in the equity investments caption on the Consolidated Balance Sheets.

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 delay. This delay in reporting is consistent from period to period.

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

	February 28, 2013		November 30, 2012
Current assets	$	58,600	$	55,351
Noncurrent assets	$	281,955	$	273,158
Current liabilities	$	45,047	$	38,188
Noncurrent liabilities	$	4,040	$	3,933

	Three Months Ended
	February 28, 2013		February 29, 2012
Revenues	$	13,026	$	12,706
Expenses	$	10,358	$	9,045
Net income	$	2,668	$	3,661

6. Long-term Debt

Revolver

On February 21, 2013, we entered into the third amendment to the amended and restated credit agreement modifying the Revolver’s Maximum Leverage Ratio covenant to allow us to maintain a ratio of Consolidated Total Indebtedness (as defined in the Revolver amendment), calculated as of the end of each fiscal quarter for the four quarters than ended, of not more than (i) 5.75 to 1.0 commencing with fiscal period ended March 31, 2013 through the fiscal period ending June 30, 2013; (ii) 5.50 to 1.0 commencing with the fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013; and (iii) 5.25 to 1.0 commencing with the fiscal period ending March 31, 2014, and for each fiscal period thereafter.

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

As of March 31, 2013, net of outstanding indebtedness of $700.0 million and letters of credit of $7.9 million, we had remaining borrowing capacity of $292.1 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the three months ended March 31, 2013 was approximately 3.2%. We do not have a public rating for the Revolver. As of March 31, 2013, we were in compliance with all covenants under the Revolver.

7. Partners’ Capital and Distributions

As of March 31, 2013, partners’ capital consisted of 95.7 million common units, 10.3 million Special Units and 22.8 million Class B Units. We will pay distributions on May 14, 2013 with respect to the quarter ended March 31, 2013.

Special Units

Absent an early conversion event, the Special Units will not be entitled to accrue distributions until the quarter commencing on October 1, 2013. If the Special Units would have been entitled to accrue and receive the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended March 31, 2013, we would have paid an aggregate of $5.7 million in distributions to the holders of the Special Units.

Class B Units

We will pay distributions to the holders of the Class B Units with respect to the quarter ended March 31, 2013 by issuing an aggregate of 527,044 additional Class B Units. If we were to pay distributions to the holders of the Class B Units in cash, rather than in additional Class B Units, at the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended March 31, 2013, the amount of cash distributions that would have been attributable to the Class B Units was $12.5 million.

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Net Income (Loss) per Common Unit

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

	Three Months Ended March 31,
	2013			2012
Net income (loss)	$	7,237		$	(110,344	)
Less:
Distributions to participating securities		(12,582	)		(131	)
Recognition of beneficial conversion feature (1)		(18,520	)		—
Participating securities’ allocable share of undistributed net loss (income)		7,460			349
Net income (loss) allocable to common units, basic and diluted	$	(16,405	)	$	(110,126	)
Weighted average number of common units outstanding, basic		95,906			79,301
Weighted average number of common units outstanding, diluted		95,906			79,340
Net income (loss) per common unit, basic	$	(0.17	)	$	(1.39	)
Net income (loss) per common unit, diluted	$	(0.17	)	$	(1.39	)

(1) Special Units and Class B Units were issued at prices below the market price of the common units into which they are convertible. The aggregate discount of $138.1 million represents a beneficial conversion feature which is considered a non-cash distribution that will be distributed ratably using the effective yield method over the period the Special Units and Class B Units are outstanding. The impact of the beneficial conversion feature is included as distributed income to Class B Units and Special Units with a corresponding reduction in net income allocable to common units in the calculation of net income (loss) per common unit for the three months ended March 31, 2013.

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

	Three Months Ended
	March 31,
	2013		2012
Special units		10,346		—
Class B units		22,618		—
Phantom units		63		—
		33,027		—

Cash Distributions

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

During the three months ended March 31, 2013 and 2012, we paid cash distributions of $52.7 million and $40.4 million.

On May 14, 2013, we will pay a $0.55 per unit quarterly distribution to common unitholders of record on May 8, 2013.

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8. Unit-Based Compensation

The PVR GP, LLC Sixth Amended and Restated Long-Term Incentive Plan (the “LTIP”) permits the grant of common units, deferred common units, unit options, restricted units and phantom units to employees and directors of our general partner and its affiliates. Common units and deferred common units granted under the LTIP are immediately vested, and we recognize compensation expenses related to those grants on the grant date. Restricted units and the time-based and performance-based phantom units granted under the LTIP generally vest over a three-year period, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period. Compensation expense related to these grants is recorded in the general and administrative expenses caption on our Consolidated Statements of Operations. During the three months ended March 31, 2013, we granted 125 thousand time-based phantom units at a weighted average grant-date fair value of $25.95 per unit.

Time-based phantom units vest over a three-year period, with one-third vesting in each year. Some of the time-based phantom units vested during the three months ended March 31, 2013. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units. The fair value of time-based phantom units is calculated based on the grant-date unit price. Time-based phantom units are entitled to non-forfeitable distribution rights which are paid quarterly along with the common unit distributions.

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,
	2013		2012
Phantom units	$	1,110	$	1,888
Director deferred and common units		154		150
	$	1,264	$	2,038

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, 2013 and December 31, 2012, our environmental liabilities were $0.8 million and $0.9 million, which represent our best estimate of the liabilities as of those dates related to our Coal and Natural Resource Management, Eastern Midstream and Midcontinent Midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. For the three months ended March 31, 2013, 61% of our total consolidated revenues and 46% of our March 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for the three months ended March 31, 2013, 47% of the segment’s revenues and 36% of the March 31, 2013 accounts receivable for the segment resulted from two customers. Within the Midcontinent Midstream segment for the three months ended March 31, 2013, 74% of the segment’s revenues and 60% of the March 31, 2013 accounts receivable for the segment resulted from five customers. These customer concentrations may impact our results of operations, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We are not aware of any financial difficulties experienced by these customers. As of March 31, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment and a $1.4 million allowance for doubtful accounts in the Coal and Natural Resource Management segment.

10. Related Party Transactions

We own a member interest in Aqua – PVR Water Services LLC (“Aqua – PVR”), which constructs and operates a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. Related to the Aqua-PVR joint venture we have executed agreements where PVR charges the joint venture fees for construction management services and accounting management services. The construction management services fee is 10% of the construction costs of a project managed by PVR. These fees began in 2012 and are not presumed to be carried out on an arm’s-length basis. The construction fees are invoiced once the

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project is complete, and the other services are invoiced once incurred or quarterly. The table below discloses the related party transactions for the period presented. The statement of operations amounts are net of eliminations and the balance sheet amounts are gross amounts.

	Three Months Ended March 31,
	2013		2012
Consolidated Statements of Operations:
Other income	$	192	$	—
General and administrative	$	5	$	—
	March 31, 2013		December 31, 2012
Consolidated Balance Sheets:
Accounts receivable	$	4,428	$	6,442
Accounts payable	$	—	$	172

11. Segment Information

Our reportable segments are as follows:

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

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

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

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	Eastern Midstream		Midcontinent Midstream			Coal and Natural Resource Management		Consolidated
Three Months Ended March 31, 2013
Revenues	$	43,897	$	190,143		$	29,371	$	263,411
Cost of midstream gas purchased		—		158,208			—		158,208
Operating costs and expenses		6,206		16,231			6,718		29,155
Depreciation, depletion & amortization		22,644		14,906			7,236		44,786
Operating income	$	15,047	$	798		$	15,417	$	31,262
Interest expense									(23,678	)
Derivatives									(441	)
Other									94
Net income								$	7,237
Additions to property and equipment	$	118,383	$	20,027		$	2,382	$	140,792
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 (loss)	$	7,900	$	(126,128	)	$	22,536	$	(95,692	)
Interest expense									(9,817	)
Derivatives									(4,951	)
Other									116
Net loss								$	(110,344	)
Additions to property and equipment	$	31,284	$	44,039		$	246	$	75,569

	Total assets
	March 31, 2013		December 31, 2012
Eastern Midstream	$	1,737,882	$	1,677,846
Midcontinent Midstream		632,022		640,437
Coal and Natural Resource Management		660,544		680,426
Totals	$	3,030,448	$	2,998,709

Forward-Looking Statements

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

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

• our ability to access external sources of capital;

• any impairment write-downs of our assets;

• the relationship between natural gas, NGL and coal prices;

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

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

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

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

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

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

• the experience and financial condition of our natural gas midstream customers and coal lessees, 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 Eastern Midstream and Midcontinent Midstream and Coal and Natural Resource Management businesses;

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

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

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

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

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

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

• hedging results;

• accidents;

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

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

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

• other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

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

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

Overview of Business

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

We manage our business in three operating segments: (i) Eastern Midstream, (ii) Midcontinent Midstream and (iii) Coal and Natural Resource Management.

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

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

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

Key Developments

During the three months ended March 31, 2013, the following general business developments and corporate actions had an impact, or will have an impact, on our results of operations. A discussion of these key developments follows:

Eastern Midstream

Construction continues on the acquired assets and existing systems. We spent approximately $72.7 million in the first three months of 2013 constructing gathering systems, trunklines and compressor stations. As a result of the construction and our producers adding well connects, our average system volumes (including both gathering and trunkline volumes) increased from 967 MMcfd in the fourth quarter of 2012 to 1,228 MMcfd in the first quarter of 2013. We expect significant development activities to continue through 2013.

Midcontinent Midstream

Construction efforts were primarily concentrated in the Panhandle and Crescent systems. We spent approximately $17.4 million in the first three months of 2013 constructing gathering systems and compressor stations. Our average system volumes decreased from 442 MMcfd in the first quarter of 2012 to 391 MMcfd in the first quarter of 2013 primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 57 MMcfd in the first quarter of 2012. Also contributing to the decrease were natural production declines and weather-related shut-in of wells, partially offset by increases related to recently completed construction and our producers adding well connects. We expect development activities on the Panhandle and Crescent systems to continue through 2013.

2013 Commodity Prices

Revenues, profitability and the future rate of growth of our Midcontinent Midstream segment is highly dependent on market demand and prevailing NGL and natural gas prices. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas. As a result, we may use derivative financial instruments to hedge commodity prices. Our current derivative financial instruments include swaps for crude oil (to hedge condensate volumes) and natural gas. We currently have three commodity derivatives, all of which expire at the end of 2013.

Revolver

On February 21, 2013, we entered into the third amendment of our credit agreement modifying the Revolver’s Maximum Leverage Ratio covenant to allow us to maintain a ratio of Consolidated Total Indebtedness (as defined in the Revolver amendment), calculated as of the end of each fiscal quarter for the four quarters than ended, of not more than (i) 5.75 to 1.0 commencing with fiscal period ended March 31, 2013 through the fiscal period ending June 30, 2013; (ii) 5.50 to 1.0 commencing with the fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013; and (iii) 5.25 to 1.0 commencing with the fiscal period ending March 31, 2014, and for each fiscal period thereafter.

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Results of Operations

Consolidated Review

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

	Three Months Ended March 31,
	2013			2012
Revenues	$	263,411		$	246,417
Expenses		(232,149	)		(342,109	)
Operating income (loss)		31,262			(95,692	)
Other income (expense)		(24,025	)		(14,652	)
Net income (loss)	$	7,237		$	(110,344	)

Eastern Midstream Segment

Three Months Ended March 31, 2013 Compared with Three Months Ended March 31, 2012

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
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Gathering fees	$	22,138	$	4,919	$	17,219			350	%
Trunkline fees		21,101		6,392		14,709			230	%
Other		658		162		496			306	%
Total revenues		43,897		11,473		32,424			283	%
Expenses
Operating		1,980		898		(1,082	)		(120	%)
General and administrative		4,226		614		(3,612	)		(588	%)
Depreciation and amortization		22,644		2,061		(20,583	)		(999	%)
Total operating expenses		28,850		3,573		(25,277	)		(707	%)
Operating income	$	15,047	$	7,900	$	7,147			90	%
Operating Statistics
Gathered volumes (MMcfd)		584		210		374			178	%
Trunkline volumes (MMcfd)		644		92		552			600	%

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The development and completion of our expansion projects and the major acquisition in May 2012 have added significant volumes to the system.

Other revenue primarily represented operations from our investment in a joint venture and related management fees. The main reason for the increase in the first quarter of 2013 related to a gain associated with the assignment of right-of-way contracts.

Expenses

Operating expenses increased due to prior and current years’ expansion projects and the major acquisition in May 2012. The related costs of these facilities included increased field salaries, supplies, chemicals and lubricants.

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

Depreciation and amortization expenses increased as a result of capital expended on acquisitions and internal growth projects.

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Midcontinent Midstream Segment

Three Months Ended March 31, 2013 Compared with Three Months Ended March 31, 2012

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
	2013		2012			(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	87,714	$	74,627		$	13,087			18	%
Natural gas liquids		100,508		117,794			(17,286	)		(15	%)
Gathering fees		778		2,544			(1,766	)		(69	%)
Other		1,143		617			526			85	%
Total revenues		190,143		195,582			(5,439	)		(3	%)
Expenses
Cost of gas purchased		158,208		165,464			7,256			4	%
Operating		10,354		11,227			873			8	%
General and administrative		5,877		6,568			691			11	%
Impairments		—		124,845			124,845			N/A
Depreciation and amortization		14,906		13,606			(1,300	)		(10	%)
Total operating expenses		189,345		321,710			132,365			41	%
Operating income (loss)	$	798	$	(126,128	)	$	126,926			101	%
Operating Statistics
Daily throughput volumes (MMcfd)		391		442			(51	)		(12	%)

Revenues

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

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 22%, from $2.74 in the first quarter of 2012 to $3.34 in the comparable period of 2013. We have been in ethane rejection mode during the first quarter of 2013, which caused the value of ethane in the natural gas stream to be more valuable than extracting it as an NGL. Partially offsetting the increase in higher natural gas prices was a decrease in throughput volumes primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 57 MMcfd in the first quarter of 2012.

NGL and condensate revenues decreased primarily due to the prices received and being in ethane rejection mode. Our average realized price received for a Conway NGL barrel in the first quarter of 2013 was $37.34 compared to $41.89 for the same period of 2012. 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.

Gathering and processing fees decreased due to the sale of the Crossroads plant. Gathering and processing fees for Crossroads in the first quarter of 2012 were $1.4 million.

Other revenues included earnings from a natural gas gathering joint venture in Wyoming and gain on sale of assets. During the first quarter of 2013, we sold assets held for sale and recognized a gain of $0.5 million.

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 and plant recoveries. We continue to enter into more fee based contracts to reduce our commodity exposure. Cost of gas purchased decreased primarily due to the sale of the Crossroads plant at the beginning of July 2012, partially offset by an increase in natural gas prices. The average NYMEX natural gas spot price increased $0.60, or 22%, from $2.74 in the first quarter of 2012 to $3.34 in the same period of 2013.

Operating expenses decreased primarily due to the sale of the Crossroads plant at the beginning of July 2012.

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General and administrative expenses decreased due to lower employee costs and corporate overhead.

During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). This impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area.

Depreciation and amortization expenses increased as a result of capital expended on internal growth projects.

Coal and Natural Resource Management Segment

Three Months Ended March 31, 2013 Compared with Three Months Ended March 31, 2012

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
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	22,951	$	33,159	$	(10,208	)		(31	%)
Other		6,420		6,203		217			3	%
Total revenues		29,371		39,362		(9,991	)		(25	%)
Expenses
Operating		3,036		3,778		742			20	%
General and administrative		3,682		4,862		1,180			24	%
Depreciation, depletion and amortization		7,236		8,186		950			12	%
Total expenses		13,954		16,826		2,872			17	%
Operating income	$	15,417	$	22,536	$	(7,119	)		(32	%)
Other data
Coal royalty tons		6,446		8,105		(1,659	)		(20	%)
Average coal royalties per ton	$	3.56	$	4.09	$	(0.53	)		(13	%)

Revenues

Coal royalties, which accounted for 78% of the Coal and Natural Resource Management segment revenues for the three months ended March 31, 2013 and 84% for the three months ended 2012, were lower in 2013 as compared to 2012. The decrease was a result of less coal being produced by our lessees and lower coal prices. The reduced demand for coal from our lessees’ customers was primarily due to domestic electrical generation switching from coal to natural gas and lower metallurgical coal pricing. Coal royalties per ton decreased because customers cannot utilize all of the coal producers have mined. The surplus has caused lower demand, decreased production and reduced prices.

Expenses

Operating expenses decreased primarily due to lower production on subleased properties. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

General and administrative expenses decreased due to lower corporate overhead and employee costs.

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

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Other

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

	Three Months Ended March 31,
	2013			2012
Operating income (loss)	$	31,262		$	(95,692	)
Other income (expense)
Interest expense		(23,678	)		(9,817	)
Derivatives		(441	)		(4,951	)
Other		94			116
Net income (loss)	$	7,237		$	(110,344	)

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

	Three Months Ended March 31,
Source	2013			2012
Interest on Revolver and bank fees	$	(5,914	)	$	(4,824	)
Interest on Senior Notes		(18,750	)		(6,188	)
Debt issuance costs and other		(1,652	)		(1,049	)
Capitalized interest		2,638			2,244
Total interest expense	$	(23,678	)	$	(9,817	)

Interest expense for the three months ended March 31, 2013 increased compared to the same period in 2012. The increase was primarily due to the new Senior Notes issued in May 2012 for $600.0 million. Also, there was an increase in Revolver interest expense related to increased amounts outstanding under the Revolver and the related margins paid on outstanding debt. Revolver amendments have increased our margins that we pay and are based upon our periodic debt covenant calculations. Debt issuance costs amortization increased in the comparable first quarters due to fees paid for a Revolver amendment and issuance of the new Senior Notes. These increases were partially offset by interest we have capitalized related to construction efforts in the Eastern Midstream and Midcontinent Midstream segments.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for 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 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. The fair value of our derivatives at March 31, 2013 was a current liability of $0.4 million.

Our derivative activity for the periods presented is summarized below:

	Three Months Ended March 31,
	2013			2012
Interest Rate Swap realized derivative loss	$	—		$	(391	)
Interest Rate Swap unrealized derivative gain		—			222
Interest Rate Swap other comprehensive income reclass		—			147
Natural gas midstream commodity realized derivative loss		(7	)		(3,250	)
Natural gas midstream commodity unrealized derivative loss		(434	)		(1,679	)
Total derivative loss	$	(441	)	$	(4,951	)

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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. 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 natural gas midstream market and coal industry, most of which are beyond our control. In March 2013, Standard and Poors decided to move our corporate rating down from BB- to B+.

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

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	7,237		$	(110,344	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities (summarized)		47,242			151,707
Net changes in operating assets and liabilities		24,936			3,804
Net cash provided by operating activities		79,415			45,167
Net cash used in investing activities (summarized)		(137,446	)		(81,859	)
Net cash provided by financing activities (summarized)		56,291			35,582
Net decrease in cash and cash equivalents	$	(1,740	)	$	(1,110	)

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the three months ended March 31, 2013 as compared to the same period in 2012 was primarily driven by increased fee-based revenues related to the Eastern Midstream segment, partially offset by a decrease in coal royalties. Additionally, there was a decrease in cash paid for derivative settlements and an increase in distributions received from our equity investments.

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,
	2013		2012
Eastern Midstream
Internal growth	$	72,700	$	26,713
Maintenance		463		—
Total		73,163		26,713
Midcontinent Midstream
Internal growth	$	17,405	$	43,146
Maintenance		3,200		3,094
Total		20,605		46,240
Coal and Natural Resource Management
Acquisitions	$	2,346	$	136
Internal growth		—		47
Maintenance		1		3
Total		2,347		186
Total capital expenditures	$	96,115	$	73,139

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Our Eastern Midstream and Midcontinent Midstream segments’ capital expenditures for the three months ended March 31, 2013 and 2012 consisted primarily of internal growth capital to expand our natural gas gathering and operational footprint in our Marcellus Shale, Panhandle and Crescent systems.

Cash Flows From Financing Activities

During the three months ended March 31, 2013 and 2012, we incurred net borrowings of $110.0 million and $76.0 million to fund our natural gas midstream projects. During the three months ended March 31, 2013 and 2012, we paid cash distributions to our unitholders of $52.7 million and $40.4 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,
	2013			2012
Reconciliation of Non-GAAP “Segment Adjusted EBITDA” to GAAP “Net income (loss)”:
Segment Adjusted EBITDA (a):
Eastern Midstream	$	37,691		$	9,961
Midcontinent Midstream		15,704			12,323
Coal and Natural Resource Management		22,653			30,722
Total segment adjusted EBITDA	$	76,048		$	53,006
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(44,786	)		(23,853	)
Impairments on PP&E and equity investments		—			(124,845	)
Interest expense		(23,678	)		(9,817	)
Derivatives		(441	)		(4,951	)
Other		94			116
Net income (loss)	$	7,237		$	(110,344	)
Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	7,237		$	(110,344	)
Depreciation, depletion and amortization		44,786			23,853
Impairments on PP&E and equity investments		—			124,845
Derivative contracts:
Derivative losses included in net income		441			4,951
Cash payments to settle derivatives for the period		(222	)		(3,641	)
Equity earnings from joint ventures, net of distributions		1,325			(741	)
Maintenance capital expenditures		(3,664	)		(3,097	)
Distributable cash flow (b)	$	49,903		$	35,826
Distribution to Partners:
Total cash distribution paid during the period	$	52,735		$	40,418

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

(b) Distributable cash flow represents net income plus DD&A, plus impairments, plus (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. 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. For comparative purposes, prior year amounts exclude replacement capital expenditures.

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Sources of Liquidity

Long-Term Debt

Revolver. As of March 31, 2013, net of outstanding indebtedness of $700.0 million and letters of credit of $7.9 million, we had remaining borrowing capacity of $292.1 million on the Revolver. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The weighted average interest rate on borrowings outstanding under the Revolver during the three months ended March 31, 2013 was approximately 3.2%. We do not have a public rating for the Revolver. As of March 31, 2013, we were in compliance with all covenants under the Revolver.

On February 21, 2013, we entered into the third amendment to the amended and restated credit agreement modifying the Revolver’s Maximum Leverage Ratio covenant to allow us to maintain a ratio of Consolidated Total Indebtedness (as defined in the Revolver amendment), calculated as of the end of each fiscal quarter for the four quarters than ended, of not more than (i) 5.75 to 1.0 commencing with fiscal period ended March 31, 2013 through the fiscal period ending June 30, 2013; (ii) 5.50 to 1.0 commencing with the fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013; and (iii) 5.25 to 1.0 commencing with the fiscal period ending March 31, 2014, and for each fiscal period thereafter.

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

Future Capital Needs and Commitments

As of March 31, 2013, our remaining borrowing capacity under the $1.0 billion Revolver of approximately $292.1 million is adequate to meet our short-term 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 2013, we expect to invest approximately $350-400 million in internal growth capital, excluding acquisitions. A significant portion of the internal growth capital expenditures is related to the Marcellus Shale system. Long-term cash requirements for acquisitions and internal growth capital are expected to be funded by operating cash flows, borrowings under the Revolver and issuances of additional debt and equity securities.

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

Environmental Matters

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

As of March 31, 2013 and December 31, 2012, our estimated minimum environmental liabilities were $0.8 million and $0.9 million, which represent our best estimate of the liabilities as of those dates related to our Coal and Natural Resource Management, Eastern Midstream and Midcontinent Midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

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Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the U.S. 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, 2012 and remained unchanged as of March 31, 2013.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

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

• Price Volatility

• Interest Rate Risk

• Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. If our customers or lessees become financially insolvent, they may or may 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 risk management positions.

We have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, intangibles and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could record a significant impairment loss on our Consolidated Statements of Operations.

Price Volatility

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

At March 31, 2013, we reported a commodity derivative liability related to the Midcontinent Midstream segment of $0.4 million related to three hedges placed with one counterparty. This concentration may impact our overall credit risk, either positively or negatively, in that this counterparty 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 this counterparty.

For the three months ended March 31, 2013 we reported a net loss for our commodity hedges of $0.4 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 and crude oil prices. These fluctuations could be significant in a volatile environment.

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

	Average Volume Per Day			Weighted Average Swap Price			Fair Value  at March 31, 2013
Crude oil swap		(barrels	)		(per barrel	)
Second quarter through the fourth quarter 2013		500		$	94.80		$	(269	)
Natural gas swaps		(MMBtu	)		(per MMBtu	)
Second quarter through the fourth quarter 2013		5,500		$	3.823			(194	)
Settlements to be received in subsequent period								29
							$	(434	)

We estimate that a $5.00 per barrel change in the crude oil price would change the fair value of our crude oil swap by $0.7 million. We estimate that a $1.00 per MMBtu change in the natural gas price would change the fair value of our natural gas swaps by $1.5 million.

Our exposure profile with respect to commodity prices depends on many factors, including inlet volumes, plant operational efficiencies, contractual terms, and the price relationship between ethane and natural gas.

We anticipate operating our plants in “ethane rejection” for the entirety of 2013. Under this operational mode, we estimate that for every $1.00 per MMBtu change in the natural gas price, our natural gas midstream gross margin and operating income for the remainder of 2013 would change by $6.6 million, excluding the effect of the natural gas hedges described above, and all other factors remaining constant. The natural gas hedges described above would reduce the net impact to $5.1 million.

Similarly, for every $5.00 per barrel change in crude oil prices, with all other factors remaining constant, and excluding the effect of the 2013 crude oil derivative described above, we estimate that our natural gas midstream gross margin and operating income would change by $1.3 million. The crude oil hedge described above would reduce the net impact to $0.6 million.

For every $0.10 per gallon increase in the price of ethane with all other factors remaining constant, we estimate that our gross margin and operating income will decrease by $3.2 million while operating in ethane rejection. Finally, for every $0.10 per gallon increase in the price of other NGLs with all other factors remaining constant, we estimate that our gross margin and operating income will increase by $3.1 million.

Interest Rate Risk

At March 31, 2013, we had no open derivative contracts related to interest rates. As of March 31, 2013, we had $700.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term and $900.0 million of Senior Notes at a fixed rate. Thus, $700.0 million, or 44%, of our outstanding indebtedness is subject to a variable interest rate at LIBOR. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver as of March 31, 2013 would costs us approximately $7.0 million in additional interest expense per year.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. For the three months ended March 31, 2013, 61% of our total consolidated revenues and 46% of our March 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for the three months ended March 31, 2013, 47% of the segment’s revenues and 36% of the March 31, 2013 accounts receivable for the segment resulted from two customers. Within the Midcontinent Midstream segment for the three months ended March 31, 2013, 74% of the segment’s revenues and 60% of the March 31, 2013 accounts receivable for the segment resulted from five customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these natural gas midstream customers. As of March 31, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment and a $1.4 million allowance for doubtful accounts in the Coal and Natural Resource Management segment.

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This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency 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 our 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 uncollectable accounts. As of March 31, 2013, no receivables were collateralized, and we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment, and $1.4 million allowance for doubtful accounts in the Coal and Natural Resource Management segment.

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 2013. 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, 2013, 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 the 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, 2012, filed on February 27, 2013.

Item 6 Exhibits

10.1	Third Amendment to Amended and Restated Credit Agreement, dated as of February 21, 2013, 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 to Registrant’s Current Report on Form 8-K filed on February 22, 2013)
10.2	PVR GP, LLC Amended and Restated Annual Incentive Plan effective as of April 23, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on April 26, 2013)*
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.

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101** The following financial information from the quarterly report on Form 10-Q of PVR Partners L.P. for the quarter ended March 31, 2013, 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.

* Management contract or compensatory plan or arrangement.

** Furnished herewith.

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SIGNATURES

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

	PVR PARTNERS, L.P.
	By:	PVR GP, LLC
Date: May 3, 2013	By:	/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer
Date: May 3, 2013	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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