FORM 10-Q

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10-Q 1 d562233d10q.htm FORM 10-Q FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

¨	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.

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 July 12, 2013, 95,724,743 common units, 23,309,784 Class B Units, and 10,346,257 Special Units representing limited partner interests were outstanding.


		Page

PART I. Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012		1

	Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2013 and 2012		1

	Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012		2

	Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2013 and 2012		3

	Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2013 and 2012		4

	Notes to Consolidated Financial Statements		5

	Forward-Looking Statements		13

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26

Item 4.	Controls and Procedures		28

PART II. Other Information

Item 1.	Legal Proceedings		28

Item 1A.	Risk Factors		28

Item 6.	Exhibits		29

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues
Natural gas	$	103,111		$	63,127		$	190,825		$	137,754
Natural gas liquids		93,470			102,130			193,978			219,924
Gathering fees		25,886			11,149			48,802			18,612
Trunkline fees		21,653			10,255			42,754			16,647
Coal royalties		23,223			29,231			46,174			62,390
Other		6,122			7,020			14,343			14,002

Total revenues		273,465			222,912			536,876			469,329


Expenses
Cost of gas purchased		167,074			140,833			325,282			306,297
Operating		17,150			14,040			32,520			29,943
General and administrative		13,172			10,999			26,957			23,043
Acquisition related costs		—			14,049			—			14,049
Impairments		—			—			—			124,845
Depreciation, depletion and amortization		46,113			28,456			90,899			52,309

Total expenses		243,509			208,377			475,658			550,486


Operating income (loss)		29,956			14,535			61,218			(81,157	)

Other income (expense)
Interest expense		(26,326	)		(15,511	)		(50,004	)		(25,328	)
Derivatives		846			8,676			405			3,725
Other		1,032			109			1,126			225

Net income (loss)	$	5,508		$	7,809			12,745			(102,535	)


Earnings (loss) per common unit, basic and diluted	$	(0.21	)	$	(0.07	)	$	(0.38	)	$	(1.39	)

Weighted average number of common units outstanding, basic and diluted		95,947			83,786			95,927			81,543

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - unaudited

(in thousands)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012

Net income (loss)	$	5,508	$	7,809		$	12,745	$	(102,535	)
Reclassification adjustment for derivative activities		—		(175	)		—		(322	)

Comprehensive income (loss)	$	5,508	$	7,634		$	12,745	$	(102,857	)

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	June 30,			December 31,
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	13,923		$	14,713
Accounts receivable, net of allowance for doubtful accounts		132,669			133,546
Assets held for sale		—			11,450
Derivative assets		425			—
Other current assets		5,368			5,446

Total current assets		152,385			165,155


Property, plant and equipment		2,690,972			2,479,802
Accumulated depreciation, depletion and amortization		(566,208	)		(490,456	)

Net property, plant and equipment		2,124,764			1,989,346


Equity investments		103,804			97,553
Goodwill		70,283			70,283
Intangible assets (net of accumulated amortization of $ 56,711 and $ 41,452)		605,341			620,600
Other long-term assets		61,233			55,772


Total assets	$	3,117,810		$	2,998,709


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	144,551		$	197,034
Deferred income		4,548			3,788
Derivative liabilities		46			—

Total current liabilities		149,145			200,822


Deferred income		11,613			15,212
Other liabilities		18,787			20,256
Senior notes		1,300,000			900,000
Revolving credit facility		457,500			590,000
Partners’ capital
Common units		576,451			671,386
Class B units		408,811			406,553
Special units		195,503			194,480

Total partners’ capital		1,180,765			1,272,419


Total liabilities and partners’ capital	$	3,117,810		$	2,998,709

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Cash flows from operating activities
Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		46,113			28,456			90,899			52,309
Impairments		—			—			—			124,845
Derivative Contracts:
Total derivative gains		(846	)		(8,676	)		(405	)		(3,725	)
Cash receipts (payments) to settle derivatives		32			(3,605	)		(190	)		(7,246	)
Non-cash interest expense		1,830			1,579			3,482			2,628
Non-cash unit-based compensation		844			1,519			2,108			3,557
Equity earnings, net of distributions received		2,349			186			3,674			(555	)
Other		(1,064	)		(51	)		(3,068	)		(698	)
Changes in operating assets and liabilities:
Accounts receivable		(12,590	)		1,984			(4	)		13,798
Accounts payable and accrued liabilities		(14,474	)		(6,121	)		(2,115	)		(15,013	)
Deferred income		(1,964	)		762			(2,111	)		1,522
Other assets and liabilities		(131	)		(367	)		7			(245	)

Net cash provided by operating activities		25,607			23,475			105,022			68,642


Cash flows from investing activities
Acquisitions		12			(850,747	)		(2,334	)		(850,943	)
Additions to property, plant and equipment		(120,903	)		(99,621	)		(259,349	)		(174,994	)
Joint venture capital contributions		—			(5,100	)		(10,200	)		(11,700	)
Proceeds from sale of assets		—			—			11,964			—
Other		290			330			1,872			640

Net cash used in investing activities		(120,601	)		(955,138	)		(258,047	)		(1,036,997	)


Cash flows from financing activities
Distributions to partners		(52,786	)		(41,265	)		(105,521	)		(81,683	)
Net proceeds from equity offering		—			577,962			—			577,962
Proceeds from issuance of senior notes		400,000			600,000			400,000			600,000
Proceeds from borrowings		155,000			165,000			290,000			251,000
Repayments of borrowings		(397,500	)		(350,000	)		(422,500	)		(360,000	)
Cash paid for debt issuance costs		(8,658	)		(18,589	)		(9,537	)		(18,589	)
Other		(112	)		—			(207	)		—

Net cash provided by financing activities		95,944			933,108			152,235			968,690


Net increase (decrease) in cash and cash equivalents		950			1,445			(790	)		335
Cash and cash equivalents – beginning of period		12,973			7,530			14,713			8,640

Cash and cash equivalents – end of period	$	13,923		$	8,975		$	13,923		$	8,975


Supplemental disclosure:
Cash paid for interest	$	43,374		$	19,132		$	49,330		$	23,826

Noncash investing activities:
Other assets acquired related to acquisition	$	—		$	4,827		$	—		$	4,827
Other liabilities assumed related to acquisition	$	—		$	33,929		$	—		$	33,929
Special units issued as consideration in an acquisition	$	—		$	191,302		$	—		$	191,302

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

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


	Common Units					Class B Units				Special Units				Total

Balance at December 31, 2012		95,633	$	671,386			22,306	$	406,553		10,346	$	194,480	$	1,272,419

Unit-based compensation		92		1,292			—		—		—		—		1,292
Distributions paid		—		(105,521	)		1,004		—		—		—		(105,521	)
Other				(170	)		—		—		—		—		(170	)
Net income		—		9,464			—		2,258		—		1,023		12,745


Balance at June 30, 2013		95,725	$	576,451			23,310	$	408,811		10,346	$	195,503	$	1,180,765


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

Balance at December 31, 2011		79,033	$	580,961			—		—		—		—	$	743		$	581,704
Unit-based compensation		60		2,822			—		—		—		—		—			2,822
Distributions paid		—		(81,683	)		—		—		—		—		—			(81,683	)
Issuance of units		9,009		177,831			21,379		400,000		10,346		191,302		—			769,133
Net Income (loss)		—		(103,770	)		—		832		—		403		—			(102,535	)
Other Comprehensive income (loss)		—		—			—		—		—		—		(322	)		(322	)


Balance at June 30, 2012		88,102	$	576,161			21,379	$	400,832		10,346	$	191,705	$	421		$	1,169,119

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

June 30, 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 a joint venture that gathers and transports 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 Accounting Standard Update (“ASU”) 2013-02, Comprehensive Income (Topic 220). The new ASU 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 disclosure requirements were 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 ASU 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 June 30, 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

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 June 30, 2013, the fair value of our fixed-rate debt was $1.3 billion.

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 June 30, 2013, Using
Description	Fair Value Measurements at June 30, 2013			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivative assets - current	$	425		$	—	$	425		$	—
Commodity derivative liabilities - current		(46	)	$	—		(46	)	$	—

Total	$	379		$	—	$	379		$	—

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 June 30, 2013 for commodities related to natural gas midstream revenues:


	Average
	Volume		Weighted Average		Fair Value at
	Per Day		Swap Price		June 30, 2013
Crude oil swap	(barrels)		(per barrel)
Third quarter through the fourth quarter 2013		500	$	94.80	$	(31	)

Natural gas swaps	(MMBtu)		(per MMBtu)
Third quarter through the fourth quarter 2013		5,500	$	3.823		425

Settlements to be paid in subsequent period						(15	)

Interest Rate Swaps

During the six months ended June 30, 2013, we did not have any open Interest Rate Swap positions. Therefore, there are no fair value measurements to disclose. During the six months ended June 30, 2012 we reported a gain in accumulated other comprehensive income (“AOCI”) of $0.4 million as of June 30, 2012 related to the Interest Rate Swaps. In connection with periodic settlements and related reclassification of other comprehensive income, we recognized $0.3 million of net hedging losses on the Interest Rate Swaps in the derivatives line on the Consolidated Statements of Operations during the six months ended June 30, 2012. See the following “Financial Statement Impact of Derivatives” section for the impact of the Interest Rate Swaps on our Consolidated Financial Statements.

Financial Statement Impact of Derivatives

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


	Location of gain (loss)	Three Months Ended					Six Months Ended
	on derivatives recognized	June 30,					June 30,
	in statement of operations	2013		2012			2013		2012
Derivatives not designated as hedging instruments:
Commodity contracts	Derivatives	$	846	$	8,503		$	405	$	3,574
Interest rate contracts	Derivatives		—		173			—		151

Total increase in net income resulting from derivatives		$	846	$	8,676		$	405	$	3,725


Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	32	$	(3,605	)	$	25	$	(7,246	)
Unrealized derivative gains	Derivatives		814		12,281			380		10,971

Total increase in net income resulting from derivatives		$	846	$	8,676		$	405	$	3,725

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 at December 31, 2012. 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 periods presented:


		Fair Values as of
		June 30, 2013
		Derivative		Derivative
	Balance Sheet Location	Assets		Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities - current	$	—	$	—
Commodity contracts	Derivative assets/liabilities - current		425		46

Total derivatives not designated as hedging instruments		$	425	$	46


Total fair value of derivative instruments		$	425	$	46

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

As of June 30, 2013, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of June 30, 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 $0.2 million and $2.3 million for the six months ended June 30, 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 $3.9 million and $1.8 million for the six months ended June 30, 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.

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


	May 31,		November 30,
	2013		2012
Current assets	$	35,565	$	55,351
Noncurrent assets	$	282,178	$	273,158
Current liabilities	$	18,800	$	38,188
Noncurrent liabilities	$	3,909	$	3,933

	Six Months Ended May 31,
	2013		2012
Revenues	$	23,947	$	27,624
Expenses	$	21,242	$	18,960
Net income	$	2,705	$	8,664

6.	Long-Term Debt

Revolver

On February 21, 2013, we entered into the third amendment to the amended and restated revolving credit agreement (the “Revolver”) 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 then ended, of not more than (i) 5.75 to 1.0 commencing with fiscal period ended March 31, 2013 through the fiscal period ended 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 (as defined in the Revolver) 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 June 30, 2013, net of outstanding indebtedness of $457.5 million and letters of credit of $10.4 million, we had remaining borrowing capacity of $532.1 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the six months ended June 30, 2013 was approximately 3.3%. We do not have a public rating for the Revolver. As of June 30, 2013, we were in compliance with all covenants under the Revolver.

Senior Notes

In May 2013, we sold $400 million of senior notes due on May 15, 2021 in a private placement with an annual interest rate of 6.5% (“6.5% Senior Notes”), which is payable semi-annually in arrears on May 15 and November 15 of each year beginning on November 15, 2013. The 6.5% Senior Notes were sold at par, equating to an effective yield to maturity of approximately 6.5%. The net proceeds from the sale of the 6.5% Senior Notes of approximately $391.0 million, after deducting fees and expenses of approximately $9.0 million, were used to repay borrowings under the Revolver. They are fully and unconditionally guaranteed by our existing and future domestic subsidiaries, subject to certain exceptions. The 6.5% 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.

We also have $300 million of 8.25% Senior Notes, issued in April 2010 and due April 2018, and $600 million of 8.375% Senior Notes, issued in May 2012 and due June 2020.

The 8.25% Senior Notes are unsecured obligations of PVR Partners, L.P. and Penn Virginia Resource Finance Corporation (“Finance Corp”). The 8.375% Senior Notes and the 6.5% Senior Notes are unsecured obligations of PVR Partners, L.P. and Penn Virginia Resource Finance Corporation II (“Finance Corp II”). Finance Corp and Finance Corp II are finance subsidiaries 100% owned by PVR Partners, L.P. Finance Corp, Finance Corp II, and PVR Partners, L.P. do not have any material independent assets or operations. The 8.25% Senior Notes, 8.375% Senior Notes and 6.5% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our other existing and future domestic restricted subsidiaries, subject to certain exceptions. The guarantees are joint and several and all subsidiary guarantors are 100% owned by PVR Partners, L.P. There are no significant restrictions on the ability of PVR, Finance Corp or Finance Corp II of any guarantor of the Senior Notes to obtain funds from their subsidiaries by dividend or loan.

7.	Partners’ Capital and Distributions

As of June 30, 2013, partners’ capital consisted of 95.7 million common units, 10.3 million Special Units and 23.3 million Class B Units. We will pay distributions on August 14, 2013 with respect to the quarter ended June 30, 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 June 30, 2013, we would pay an aggregate of $5.7 million in distributions to the holders of the Special Units on August 14, 2013.

Class B Units

We will pay distributions to the holders of the Class B Units with respect to the quarter ended June 30, 2013 by issuing an aggregate of 470,099 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 distribution rate to which the holders of our common units are entitled with respect to the quarter ended June 30, 2013, the amount of cash distributions that would have been attributable to the Class B Units was $12.8 million.

Net Income (Loss) per Common Unit

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)
Less:
Distributions to participating securities		(12,865	)		(5,747	)		(25,449	)		(5,822	)
Recognition of beneficial conversion feature (1)		(20,254	)		(11,355	)		(38,774	)		(11,355	)
Participating securities’ allocable share of undistributed net loss		7,824			3,090			15,284			6,245

Net loss allocable to common units, basic and diluted	$	(19,787	)	$	(6,203	)	$	(36,194	)	$	(113,467	)


Weighted average number of common units outstanding, basic and diluted		95,947			83,786			95,927			81,543

Net loss per common unit, basic and diluted	$	(0.21	)	$	(0.07	)	$	(0.38	)	$	(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 $139.2 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 loss per common unit for the three and six months ended June 30, 2013 and 2012.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

Special units		10,346		5,116		10,346		2,558
Class B units		23,136		10,572		22,879		5,286
Phantom units		48		47		48		40

		33,530		15,735		33,273		7,884

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 unit holders for any one or more of the next four quarters.

During the three and six months ended June 30, 2013, we paid cash distributions of $52.8 million and $105.5 million.

During the three and six months ended June 30, 2012, we paid cash distributions of $41.3 million and $81.7 million.

On August 14, 2013, we will pay a $0.55 per unit quarterly distribution to common unit holders of record on August 7, 2013.

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 six months ended June 30, 2013, we granted 249 thousand phantom units at a weighted average grant-date fair value of $22.54 per unit including 147 thousand time-based phantom units and 102 thousand performance-based phantom units.

Time-based phantom units generally vest over a three-year period, with one-third vesting in each year. Certain of the time-based phantom units vested during the six months ended June 30, 2013. A portion of the vested units was 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 generally entitled to non-forfeitable distribution rights which are paid quarterly along with the common unit distributions.

Performance-based phantom units cliff-vest at the end of a three-year period. The number of units that vest could range from 0% to 200% of the number of performance-based phantom units initially granted and depends on the outcome of unit market performance compared to peers and, for certain grants, key results of operations metrics. Performance-based phantom units are entitled to forfeitable distribution equivalent rights which accumulate over the term of the units and will be paid in cash to the grantees at the date of vesting. The fair value of each performance-based phantom unit granted in 2013 was estimated as $17.60 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.


	2013
Expected volatility		28.20	%
Expected life		2.7 years
Risk-free interest rate		0.31	%

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				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Phantom units	$	689	$	1,369	$	1,799	$	3,257
Director deferred and common units		155		150		309		300

	$	844	$	1,519	$	2,108	$	3,557

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.

On July 24, 2012, the Pennsylvania Department of Environmental Protection (“PA DEP”) presented the Partnership’s subsidiary, PVR Marcellus Gas Gathering, LLC, with a proposed Consent Assessment of Civil Penalty totaling approximately $0.2 million in connection with alleged erosion and sediment control violations incurred during construction of its pipelines and related facilities in Lycoming County, Pennsylvania. On May 7, 2013, PVR Marcellus Gas Gathering, LLC entered into a Consent Assessment of Civil Penalty with the PA DEP, settling and resolving the penalty assessment and, pursuant to the agreement, agreed to pay a $0.15 million civil penalty to settle the alleged violations. The penalty was recorded in operating expenses on the Consolidated Statement of Operations.

Environmental Compliance

As of June 30, 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 six months ended June 30, 2013, 59% of our total consolidated revenues and 49% of our June 30, 2013 consolidated accounts receivable resulted from eight of our natural gas midstream customers. Within the Eastern Midstream segment for the six months ended June 30, 2013, 57% of the segment’s revenues and 52% of the June 30, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for the six months ended June 30, 2013, 68% of the segment’s revenues and 55% of the June 30, 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.

Coal royalties from lessees are impacted by several factors that we generally cannot control. The number of tons mined is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. Legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and which may require us, our lessees or lessees’ customers to change operations significantly or incur substantial costs.

As of June 30, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment and a $1.3 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 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 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 statements of operations amounts are net of eliminations.


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Consolidated Statements of Operations:
Other income	$	72	$	1,240	$	264	$	1,240
General and administrative	$	6	$	16	$	11	$	16


	June 30, 2013		December 31, 2012
Consolidated Balance Sheets:
Accounts receivable	$	4,575	$	6,442
Accounts payable	$	—	$	172

11.

Segment Information

Our reportable segments are as follows:

•


	Eastern Midstream			Midcontinent Midstream			Coal and Natural Resource Management		Consolidated
Three Months Ended June 30, 2013
Revenues	$	45,438		$	197,867		$	30,160	$	273,465
Cost of midstream gas purchased		—			167,074			—		167,074
Operating costs and expenses		7,348			15,867			7,107		30,322
Depreciation, depletion & amortization		23,462			15,054			7,597		46,113

Operating income (loss)	$	14,628		$	(128	)	$	15,456	$	29,956

Interest expense										(26,326	)
Derivatives										846
Other										1,032

Net income									$	5,508

Additions to property and equipment	$	100,604		$	20,244		$	43	$	120,891

Three Months Ended June 30, 2012
Revenues	$	21,124		$	167,949		$	33,839	$	222,912
Cost of midstream gas purchased		—			140,833			—		140,833
Operating costs and expenses		3,465			14,432			7,142		25,039
Acquisition related costs		14,049			—			—		14,049
Depreciation, depletion & amortization		8,394			11,700			8,362		28,456

Operating income (loss)	$	(4,784	)	$	984		$	18,335	$	14,535

Interest expense										(15,511	)
Derivatives										8,676
Other										109

Net income									$	7,809

Additions to property and equipment	$	917,713		$	31,936		$	719	$	950,368

Six Months Ended June 30, 2013
Revenues	$	89,335		$	388,010		$	59,531	$	536,876
Cost of midstream gas purchased		—			325,282			—		325,282
Operating costs and expenses		13,554			32,098			13,825		59,477
Depreciation, depletion & amortization		46,106			29,960			14,833		90,899

Operating income	$	29,675		$	670		$	30,873	$	61,218

Interest expense										(50,004	)
Derivatives										405
Other										1,126

Net income									$	12,745

Additions to property and equipment	$	218,987		$	40,271		$	2,425	$	261,683

Six Months Ended June 30, 2012
Revenues	$	32,597		$	363,531		$	73,201	$	469,329
Cost of midstream gas purchased		—			306,297			—		306,297
Operating costs and expenses		4,977			32,227			15,782		52,986
Acquisition related costs		14,049			—			—		14,049
Impairments		—			124,845			—		124,845
Depreciation, depletion & amortization		10,455			25,307			16,547		52,309

Operating income (loss)	$	3,116		$	(125,145	)	$	40,872	$	(81,157	)

Interest expense										(25,328	)
Derivatives										3,725
Other										225

Net loss									$	(102,535	)

Additions to property and equipment	$	948,997		$	75,975		$	965	$	1,025,937


	Total assets
	June 30, 2013		December 31, 2012

Eastern Midstream	$	1,816,453	$	1,677,846
Midcontinent Midstream		636,349		640,437
Coal and Natural Resource Management		665,008		680,426

Totals	$	3,117,810	$	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;

•

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.

•

Key Developments

During the six months ended June 30, 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 invested approximately $170.2 million in the first six 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 1,310 MMcfd in the second quarter of 2013.

Midcontinent Midstream

Construction efforts were primarily concentrated in the Panhandle and Crescent systems. We invested approximately $30.8 million in the first six months of 2013 constructing gathering systems and compressor stations. Our average system volumes decreased from 448 MMcfd in the first half of 2012 to 387 MMcfd in the first half of 2013 primarily due to the sale of the Crossroads plant at the beginning of July 2012. The Crossroads plant processed approximately 55 MMcfd in the first half of 2012. Also contributing to the decrease were natural production declines and weather-related shut-ins of wells, partially offset by increases related to recently completed construction and our producers adding well connects.

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.

Results of Operations

Consolidated Review

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues	$	273,465		$	222,912		$	536,876		$	469,329
Expenses		(243,509	)		(208,377	)		(475,658	)		(550,486	)

Operating income (loss)		29,956			14,535			61,218			(81,157	)
Other income (expense)		(24,448	)		(6,726	)		(48,473	)		(21,378	)

Net income (loss)	$	5,508		$	7,809			12,745			(102,535	)

Eastern Midstream Segment

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 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:


							Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Three Months Ended June 30,
	2013			2012
Financial Highlights
Revenues
Gathering fees	$	25,003		$	9,385		$	15,618			166	%
Trunkline fees		21,653			10,255			11,398			111	%
Other		(1,218	)		1,484			(2,702	)		(182	%)

Total revenues		45,438			21,124			24,314			115	%


Expenses
Operating		2,875			1,189			(1,686	)		(142	%)
General and administrative		4,473			2,276			(2,197	)		(97	%)
Acquisition related costs		—			14,049			14,049			N/A
Depreciation and amortization		23,462			8,394			(15,068	)		(180	%)

Total operating expenses		30,810			25,908			(4,902	)		(19	%)


Operating income (loss)	$	14,628		$	(4,784	)	$	19,412			(406	%)


Operating Statistics
Gathered volumes (MMcfd)		612			336			276			82	%
Trunkline volumes (MMcfd)		698			120			578			482	%

Revenues

Gathering and trunkline fees have increased due to the significant increase in volumes. The development and completion of our expansion projects and the acquisition of Chief Gathering LLC 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 decrease in equity earnings from the joint venture relates to decreased volumes transported in the comparable periods. The timing of water flow to various producers relates to the producers’ drilling schedules. The related need for water changes over time due to the number of rigs running and timing of such drilling.

Expenses

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

General and administrative expenses increased due to the addition of personnel, increased office space, equity compensation and corporate overhead.

Acquisition costs in 2012 relate to the one-time expenses of the Chief acquisition, which included investment banking, legal and due diligence fees and expenses.

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

Eastern Midstream Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 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:


						Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Six Months Ended June 30,
	2013			2012
Financial Highlights
Revenues
Gathering fees	$	47,141		$	14,304	$	32,837			230	%
Trunkline fees		42,754			16,647		26,107			157	%
Other		(560	)		1,646		(2,206	)		(134	%)

Total revenues		89,335			32,597		56,738			174	%


Expenses
Operating		4,855			2,087		(2,768	)		(133	%)
General and administrative		8,699			2,890		(5,809	)		(201	%)
Acquisition related costs		—			14,049		14,049			N/A
Depreciation and amortization		46,106			10,455		(35,651	)		(341	%)

Total operating expenses		59,660			29,481		(30,179	)		(102	%)


Operating income	$	29,675		$	3,116	$	26,559			852	%


Operating Statistics
Gathered volumes (MMcfd)		598			273		325			119	%
Trunkline volumes (MMcfd)		671			106		565			533	%

Revenues

Expenses

General and administrative expenses increased due to the addition of personnel, increased office space, equity compensation and corporate overhead.

Acquisition costs in 2012 relate to the one-time expenses of the Chief acquisition, which included investment banking, legal and due diligence fees and expenses.

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

Midcontinent Midstream Segment

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 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:


						Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Three Months Ended June 30,
	2013			2012
Financial Highlights
Revenues
Natural gas	$	103,111		$	63,127	$	39,984			63	%
Natural gas liquids		93,470			102,130		(8,660	)		(8	%)
Gathering fees		883			1,764		(881	)		(50	%)
Other		403			928		(525	)		(57	%)

Total revenues		197,867			167,949		29,918			18	%


Expenses
Cost of gas purchased		167,074			140,833		(26,241	)		(19	%)
Operating		10,574			9,251		(1,323	)		(14	%)
General and administrative		5,293			5,181		(112	)		(2	%)
Depreciation and amortization		15,054			11,700		(3,354	)		(29	%)

Total operating expenses		197,995			166,965		(31,030	)		(19	%)


Operating income (loss)	$	(128	)	$	984	$	(1,112	)		113	%


Operating Statistics
Daily throughput volumes (MMcfd)		382			453		(71	)		(16	%)

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. The Antelope Hills facility became operational in 2012. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 84%, from $2.22 in the second quarter of 2012 to $4.09 in the comparable period of 2013. We have been in ethane rejection mode during 2013 due to the compressed pricing differentials between ethane and natural gas and retaining ethane in the natural gas stream has been 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 52 MMcfd in the second quarter of 2012.

NGL and condensate revenues decreased primarily due to being in ethane rejection mode. Offsetting the lack of ethane revenues was a minor increase in our average realized price received for a Conway NGL barrel in the second quarter of 2013, which was $31.51 compared to $29.49 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 second quarter of 2012 were $0.8 million.

Other revenues included decreased earnings from our natural gas gathering joint venture in Wyoming due to decreased volumes. Also, marketing fees decreased due to a marketing agreement expiring in 2012, and lower producer services fees were assessed in 2013 due to expired agreements.

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 increased primarily due to the average NYMEX natural gas spot price increasing by $1.87, or 84%, from $2.22 in the second quarter of 2012 to $4.09 in the same period of 2013. Offsetting the increase was the sale of the Crossroads plant at the beginning of July 2012.

Operating expenses increased primarily due to personnel costs, compressor rentals, chemicals and utility costs. Some of these increased costs relate to the new Antelope Hills facility that became operational during 2012. The increase was offset by the sale of the Crossroads plant at the beginning of July 2012.

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

Midcontinent Midstream Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 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:


						Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Six Months Ended June 30,
	2013		2012
Financial Highlights
Revenues
Natural gas	$	190,825	$	137,754		$	53,071			39	%
Natural gas liquids		193,978		219,924			(25,946	)		(12	%)
Gathering fees		1,661		4,308			(2,647	)		(61	%)
Other		1,546		1,545			1			0	%

Total revenues		388,010		363,531			24,479			7	%


Expenses
Cost of gas purchased		325,282		306,297			(18,985	)		(6	%)
Operating		20,928		20,478			(450	)		(2	%)
General and administrative		11,170		11,749			579			5	%
Impairments		—		124,845			124,845			N/A
Depreciation and amortization		29,960		25,307			(4,653	)		(18	%)

Total operating expenses		387,340		488,676			101,336			21	%


Operating income (loss)	$	670	$	(125,145	)	$	125,815			(101	%)


Operating Statistics
Daily throughput volumes (MMcfd)		387		448			(61	)		(14	%)

Revenues

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 50%, from $2.48 in the first half of 2012 to $3.71 in the comparable period of 2013. We have been in ethane rejection mode during the first half of 2013 due to compressed pricing between ethane and natural gas and retaining ethane in the natural gas stream has been 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 55 MMcfd in the first half 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 half of 2013 was $34.43 compared to $35.69 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 half of 2012 were $2.2 million.

Other revenues remained relatively constant with offsetting increases and decreases. During the first quarter of 2013, we sold a plant under construction and recorded a gain of $0.5 million. This increase was offset by decreased earnings from a natural gas gathering joint venture in Wyoming due to decreased volumes. Also, marketing fees decreased due to a marketing agreement expiring in 2012, and lower producer services fees were assessed in 2013 due to expired agreements.

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 increased primarily due to the average NYMEX natural gas spot price increasing by $1.23, or 50%, from $2.48 in the first half of 2012 to $3.71 for the same period of 2013. Offsetting the increase was the sale of the Crossroads plant at the beginning of July 2012.

Operating expenses increased due to the startup operations of the new Antelope Hills facility, which became operational during 2012. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash. The increase was offset by the sale of the Crossroads plant at the beginning of July 2012.

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 June 30, 2013 Compared with Three Months Ended June 30, 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:


					Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Three Months Ended June 30,
	2013		2012
Financial Highlights
Revenues
Coal royalties	$	23,223	$	29,231	$	(6,008	)		(21	%)
Other		6,937		4,608		2,329			51	%

Total revenues		30,160		33,839		(3,679	)		(11	%)


Expenses
Operating		3,701		3,600		(101	)		(3	%)
General and administrative		3,406		3,542		136			4	%
Depreciation, depletion and amortization		7,597		8,362		765			9	%

Total expenses		14,704		15,504		800			5	%


Operating income	$	15,456	$	18,335	$	(2,879	)		(16	%)


Other data

Coal royalty tons		6,893		7,776		(883	)		(11	%)

Average coal royalties per ton	$	3.37	$	3.76	$	(0.39	)		(10	%)

Revenues

Coal royalties, which accounted for 77% of the Coal and Natural Resource Management segment revenues for the three months ended June 30, 2013 and 86% 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 royalty tonnage decreased because customers cannot utilize all of the coal producers have mined. The surplus due to lower demand has resulted in decreased production and reduced prices.

Other revenues increased due to minimum forfeitures recognized from a lessee declaring bankruptcy. We are actively seeking a new lessee to mine the minerals from the vacated property.

Expenses

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

General and administrative expenses decreased due to lower employee costs.

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

Coal and Natural Resource Management Segment

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 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:


					Favorable (Unfavorable)			% Change Favorable (Unfavorable)
	Six Months Ended June 30,
	2013		2012
Financial Highlights
Revenues
Coal royalties	$	46,174	$	62,390	$	(16,216	)		(26	%)
Other		13,357		10,811		2,546			24	%

Total revenues		59,531		73,201		(13,670	)		(19	%)

Expenses
Operating		6,737		7,378		641			9	%
General and administrative		7,088		8,404		1,316			16	%
Depreciation, depletion and amortization		14,833		16,547		1,714			10	%

Total expenses		28,658		32,329		3,671			11	%


Operating income	$	30,873	$	40,872	$	(9,999	)		(24	%)


Other data

Coal royalty tons		13,339		15,881		(2,542	)		(16	%)

Average coal royalties per ton	$	3.46	$	3.93	$	(0.47	)		(12	%)

Revenues

Coal royalties, which accounted for 78% of the Coal and Natural Resource Management segment revenues for the six months ended June 30, 2013 and 85% for the six 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 royalty tonnage decreased because customers cannot utilize all of the coal producers have mined. The surplus due to lower demand has resulted in decreased production and reduced prices.

Other revenues increased due to minimum forfeitures recognized from a lessee declaring bankruptcy. We are actively seeking a new lessee to mine the minerals from the vacated property.

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 to other mineral owners.

General and administrative expenses decreased due to lower employee costs.

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

Other

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Operating income (loss)	$	29,956		$	14,535		$	61,218		$	(81,157	)
Other income (expense)
Interest expense		(26,326	)		(15,511	)		(50,004	)		(25,328	)
Derivatives		846			8,676			405			3,725
Other		1,032			109			1,126			225

Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)

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


	Three Months Ended June 30,						Six Months Ended June 30,
Source	2013			2012			2013			2012
Interest on Revolver and bank fees	$	(5,639	)	$	(5,152	)	$	(11,553	)	$	(9,977	)
Interest on Senior Notes		(22,433	)		(12,329	)		(41,183	)		(18,517	)
Debt issuance costs and other		(1,830	)		(1,580	)		(3,482	)		(2,628	)
Capitalized interest		3,576			3,550			6,214			5,794

Total interest expense	$	(26,326	)	$	(15,511	)	$	(50,004	)	$	(25,328	)

Interest expense for the three and six months ended June 30, 2013 increased compared to the same period in 2012. The increase was primarily due to the 6.5% Senior Notes issued in May 2013 for $400 million and the 8.375% Senior Notes issued in May 2012 for $600 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 periods due to fees paid for a Revolver amendment and issuance of the 6.5% 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 net fair value of our derivatives at June 30, 2013 was a current asset of $0.4 million.

Our derivative activity for the periods presented is summarized below:


	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Interest Rate Swap realized derivative loss	$	—	$	(408	)	$	—	$	(799	)
Interest Rate Swap unrealized derivative gain		—		406			—		628
Interest Rate Swap other comprehensive income reclass		—		175			—		322
Natural gas midstream commodity realized derivative gain (loss)		32		(3,197	)		25		(6,447	)
Natural gas midstream commodity unrealized derivative gain		814		11,700			380		10,021

Total derivative gain	$	846	$	8,676		$	405	$	3,725

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 decreased our corporate rating from BB- to B+.

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


	Six Months Ended June 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	12,745		$	(102,535	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities (summarized)		96,500			171,115
Net changes in operating assets and liabilities		(4,223	)		62

Net cash provided by operating activities		105,022			68,642
Net cash used in investing activities (summarized)		(258,047	)		(1,036,997	)
Net cash provided by financing activities (summarized)		152,235			968,690

Net increase (decrease) in cash and cash equivalents	$	(790	)	$	335

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the six months ended June 30, 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 acquisition related costs and derivative settlements, and an increase in distributions received from our equity investments. These favorable variances were offset by an increase in interest expense related to increased debt balances and effective interest rates.

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, which include the effects of noncash investing activities and changes in accounts payable and accrued expenses for the periods presented:


	Six Months Ended June 30,
	2013		2012
Eastern Midstream
Acquisitions (1)	$	—	$	1,041,351
Internal growth		170,238		133,739
Maintenance		1,260		866

Total		171,498		1,175,956


Midcontinent Midstream
Internal growth	$	30,815	$	65,060
Maintenance		6,504		7,572

Total		37,319		72,632


Coal and Natural Resource Management
Acquisitions	$	2,334	$	836
Internal growth		1		58
Maintenance		50		10

Total		2,385		904


Total capital expenditures	$	211,202	$	1,249,492

(1)	Chief Acquisition in May 2012, for which the noncash investing activities are noted in the consolidated statements of cash flows, included an initial purchase price allocation of $637.0 million to intangible assets and $71.0 million to goodwill.

Excluding the Chief Acquisition, our Eastern Midstream and Midcontinent Midstream segments’ capital expenditures for the six months ended June 30, 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 six months ended June 30, 2013, we received funds from the private placement of $400 million in new Senior Notes. The net proceeds of approximately $391.0 million were used to pay down a portion of the Revolver. In total for the six months ended June 30, 2013, we repaid borrowings of $422.5 million. During the same period we incurred borrowings of $290.0 million to fund our natural gas midstream capital expenditures and other working capital needs. During the six months ended June 30, 2012, we received funds from the issuance of $600 million in Senior Notes and $578.0 million from the issuance of Class B Units and common units to institutional investors in private offerings. A majority of the funds were used to finance the Chief Acquisition and the remainder was used to pay down a portion of the Revolver. During the six months ended June 30, 2012, we incurred net borrowings of $109.0 million to fund our natural gas midstream capital expenditures.

During the six months ended June 30, 2013 and 2012, we paid cash distributions to our unitholders of $105.5 million and $81.7 million, respectively. The number of common units outstanding increased primarily due to equity offerings in May 2012 and November 2012.

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Reconciliation of Non-GAAP “Total Segment Adjusted EBITDA” to GAAP “Net income (loss)”:

Segment Adjusted EBITDA (a):
Eastern Midstream	$	38,090		$	17,659		$	75,781		$	27,620
Midcontinent Midstream		14,926			12,684			30,630			25,007
Coal and Natural Resource Management		23,053			26,697			45,706			57,419

Total segment adjusted EBITDA	$	76,069		$	57,040		$	152,117		$	110,046
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(46,113	)		(28,456	)		(90,899	)		(52,309	)
Impairments on PP&E		—			—			—			(124,845	)
Acquisition related costs		—			(14,049	)		—			(14,049	)
Interest expense		(26,326	)		(15,511	)		(50,004	)		(25,328	)
Derivatives		846			8,676			405			3,725
Other		1,032			109			1,126			225

Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)
Depreciation, depletion and amortization		46,113			28,456			90,899			52,309
Impairments on PP&E		—			—			—			124,845
Acquisition related costs		—			14,049			—			14,049
Derivative contracts:
Derivative gains included in net income		(846	)		(8,676	)		(405	)		(3,725	)
Cash receipts (payments) to settle derivatives for the period		32			(3,605	)		(190	)		(7,246	)
Equity earnings from joint ventures, net of distributions		2,349			186			3,674			(555	)
Maintenance capital expenditures		(4,150	)		(5,351	)		(7,814	)		(8,448	)


Distributable cash flow (b)	$	49,006		$	32,868		$	98,909		$	68,694


Distribution to Partners:

Total cash distribution paid during the period	$	52,786		$	41,265		$	105,521		$	81,683

(a)

Segment Adjusted EBITDA, or earnings before interest, tax and depreciation, depletion and amortization (“DD&A”), represents net income plus DD&A, plus impairments, plus acquisition related costs, plus interest expense, minus derivative gains and other items included in net income. 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. Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

(b)

Distributable cash flow represents net income plus DD&A, plus impairments, plus acquisition related costs, 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.

Sources of Liquidity

Long-Term Debt

Revolver. As of June 30, 2013, net of outstanding indebtedness of $457.5 million and letters of credit of $10.4 million, we had remaining borrowing capacity of $532.1 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 six months ended June 30, 2013 was approximately 3.3%. We do not have a public rating for the Revolver. As of June 30, 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 revolving 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 ended 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.

Senior Notes

In May 2013, we sold $400 million of senior notes due on May 15, 2021 in a private placement with an annual interest rate of 6.5% (“Senior Notes”), which is payable semi-annually in arrears on May 15 and November 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 6.5%. The net proceeds from the sale of the Senior Notes of approximately $391.0 million, after deducting fees and expenses of approximately $9.0 million, were used to repay borrowings under the Revolver. They are fully and unconditionally guaranteed by our existing and future domestic subsidiaries, subject to certain exceptions. 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.

Future Capital Needs and Commitments

As of June 30, 2013, our remaining borrowing capacity under the $1.0 billion Revolver of approximately $532.1 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. Funding sources for future acquisition and other capital expenditures are dependent on the size of any such acquisition or capital spending program, and are expected to be provided by a combination of cash flows provided by operating activities and borrowings, and potentially with the proceeds from the issuance of additional debt or equity financing. The availability of debt financing and our ability to periodically use equity financing through the issuance of new common units 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 June 30, 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.

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 disclosed in PVR’s Annual Report on Form 10-K for the year ended December 31, 2012. The information below enhances the previously disclosed critical accounting estimates.

Impairments

The Eastern Midstream, Midcontinent Midstream and Coal and Natural Resource Management segments 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, decreases in commodity prices, changes in the business environment or deteriorations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows.

We review long-lived assets to be held and used, including definite-lived intangible assets, whenever triggering events or circumstances indicate that the carrying value of those assets may not be recoverable. Triggering events include, but are not limited to, changes in operations; decreases in commodity prices, the amounts of which may vary depending on the asset involved; changes in the business environment; or deteriorations of market conditions. When a triggering event occurs, we estimate the future cash flows of the related assets. Our estimates of future cash flows depend on our projections of revenues and expenses for future periods. These projections are driven by our estimates or evaluation of growth rates, changes in market conditions, and changes in prices received or paid, among other factors. When the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows, 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.

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 June 30, 2013, we reported a net commodity derivative asset 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 six months ended June 30, 2013 we reported a net gain 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.

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


	Average Volume Per Day		Weighted Average Swap Price		Fair Value at June 30, 2013
Crude oil swap	(barrels)		(per barrel)
Third quarter through the fourth quarter 2013		500	$	94.80	$	(31	)

Natural gas swaps	(MMBtu)		(per MMBtu)
Third quarter through the fourth quarter 2013		5,500	$	3.823		425

Settlements to be paid in subsequent period						(15	)

Net derivative asset					$	379

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 $0.5 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 $1.0 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 remainder 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 $7.8 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 $6.8 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 $1.4 million. The crude oil hedge described above would reduce the net impact to $0.9 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 $1.6 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 $1.3 million.

Interest Rate Risk

At June 30, 2013, we had no open derivative contracts related to interest rates. As of June 30, 2013, we had $457.5 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term and $1.3 billion of Senior Notes at a fixed rate. Thus, $457.5 million, or 26%, 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 June 30, 2013 would cost us approximately $4.6 million in additional interest expense per year.

Customer Credit Risk

Coal royalties from lessees are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. Legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and which may require us, our lessees or lessees’ customers to change operations significantly or incur substantial costs.

These customer concentrations increase 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 June 30, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment and a $1.3 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 June 30, 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, reported accurately and on a timely basis, accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 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.

Part I, Item 1A, of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012, filed on February 27, 2013, includes a detailed discussion of the Partnership’s risk factors. The information below provides updates to the previously disclosed risk factors and when read in conjunction with the risk factors and information disclosed in the Partnership’s 2012 Annual Report on Form 10-K represent our currently known material risks.

Our common units may experience price volatility.

Our common unit price has experienced volatility in the past, and volatility in the price of our common units may occur in the future as a result of any of the risks described in our other public filings with the Securities and Exchange Commission. For instance, our common units may experience price volatility as a result of changes in investor sentiment with respect to our competitors, our business partners and our industry in general, which may be influenced by volatility in prices for natural gas, NGLs and coal. In addition, the securities markets have from time to time experienced significant price and volume fluctuations that are unrelated to the operating performance of particular companies but affect the market price of their securities. These market fluctuations may also materially and adversely affect the market price of our common units.

Item 6

Exhibits


Exhibit Number	Exhibit Description	Filed Herewith	Furnished Herewith

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

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.	X

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.	X

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

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

101	The following financial information from the quarterly report on Form 10-Q of PVR Partners L.P. for the quarter ended June 30, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Operations, (ii) Consolidated Statements of Comprehensive Income (Loss) (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Cash Flows, (v) Consolidated Statement of Partner’s Capital and (vi) Notes to Consolidated Financial Statements.	X

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: July 29, 2013	By:	/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer

Date: July 29, 2013	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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