PVR Partners, L. P. 10Q 2013 Q3 Quarterly report

PVR Partners, L. P. (PVR) Inactive 10-Q2013 Q3 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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 October 22, 2013, 101,837,863 common units, 23,779,883 Class B Units, and 10,346,257 Special Units representing limited partner interests were outstanding.


		Page

PART I.	Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012		1

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

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

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

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

	Notes to Consolidated Financial Statements		5

	Forward-Looking Statements		14

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29

Item 4.	Controls and Procedures		31

PART II.	Other Information

Item 1.	Legal Proceedings		32

Item 1A.	Risk Factors		32

Item 6.	Exhibits		34

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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Revenues
Natural gas	$	92,005		$	78,026		$	282,830		$	215,780
Natural gas liquids		104,585			96,237			298,563			316,161
Gathering fees		24,673			15,482			73,475			34,094
Trunkline fees		27,389			11,747			70,143			28,394
Coal royalties		20,816			28,760			66,990			91,150
Gain on sale of assets		—			31,292			—			31,292
Other		19,496			7,303			33,839			21,305

Total revenues		288,964			268,847			825,840			738,176


Expenses
Cost of gas purchased		163,824			147,246			489,106			453,543
Operating		17,506			17,587			50,026			47,530
General and administrative		13,402			11,531			40,359			34,574
Acquisition related costs		—			—			—			14,049
Impairments		—			—			—			124,845
Depreciation, depletion and amortization		47,133			31,992			138,032			84,301

Total expenses		241,865			208,356			717,523			758,842


Operating income (loss)		47,099			60,491			108,317			(20,666	)

Other income (expense)
Interest expense		(28,358	)		(20,288	)		(78,362	)		(45,616	)
Derivatives		(965	)		(1,524	)		(560	)		2,201
Other		112			104			1,238			329

Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)


Earnings (loss) per common unit, basic and diluted	$	(0.09	)	$	0.16		$	(0.47	)	$	(1.14	)

Weighted average number of common units outstanding, basic and diluted		96,983			88,366			96,283			83,834

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - unaudited

(in thousands)


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013		2012

Net income (loss)	$	17,888	$	38,783		$	30,633	$	(63,752	)
Reclassification adjustment for derivative activities		—		(201	)		—		(523	)

Comprehensive income (loss)	$	17,888	$	38,582		$	30,633	$	(64,275	)

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	September 30,			December 31,
	2013			2012

Assets
Current assets
Cash and cash equivalents	$	7,901		$	14,713
Accounts receivable, net of allowance for doubtful accounts		136,279			133,546
Assets held for sale		—			11,450
Derivative assets		229			—
Other current assets		5,127			5,446

Total current assets		149,536			165,155


Property, plant and equipment		2,771,684			2,479,802
Accumulated depreciation, depletion and amortization		(605,592	)		(490,456	)

Net property, plant and equipment		2,166,092			1,989,346


Equity investments		57,863			97,553
Goodwill		70,283			70,283
Intangible assets (net of accumulated amortization of $64,340 and $41,452)		597,712			620,600
Other long-term assets		58,794			55,772


Total assets	$	3,100,280		$	2,998,709


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	159,225		$	197,034
Deferred income		5,886			3,788
Derivative liabilities		691			—

Total current liabilities		165,802			200,822


Deferred income		12,488			15,212
Other liabilities		18,488			20,256
Senior notes		1,300,000			900,000
Revolving credit facility		332,500			590,000
Partners’ capital
Common units		662,039			671,386
Class B units		412,044			406,553
Special units		196,919			194,480

Total partners’ capital		1,271,002			1,272,419


Total liabilities and partners’ capital	$	3,100,280		$	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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Cash flows from operating activities
Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on sale of assets		(14,302	)		(31,292	)		(14,302	)		(31,292	)
Depreciation, depletion and amortization		47,133			31,992			138,032			84,301
Impairments		—			—			—			124,845
Derivative Contracts:
Total derivative (gains) losses		965			1,524			560			(2,201	)
Cash receipts (payments) to settle derivatives		(123	)		(1,332	)		(313	)		(8,578	)
Non-cash interest expense		1,917			1,589			5,399			4,217
Non-cash unit-based compensation		1,248			1,086			3,356			4,643
Equity earnings, net of distributions received		1,961			697			5,635			142
Other		(291	)		(231	)		(3,359	)		(929	)
Changes in operating assets and liabilities:
Accounts receivable		(3,397	)		(9,890	)		(3,401	)		3,908
Accounts payable and accrued liabilities		18,534			31,594			16,419			16,581
Deferred income		2,213			1,840			102			3,362
Other assets and liabilities		345			(210	)		352			(455	)

Net cash provided by operating activities		74,091			66,150			179,113			134,792


Cash flows from investing activities
Acquisitions		—			787			(2,334	)		(850,156	)
Additions to property, plant and equipment		(84,754	)		(173,455	)		(344,103	)		(348,449	)
Joint venture capital contributions		(500	)		(10,200	)		(10,700	)		(21,900	)
Proceeds from sale of assets		58,628			62,271			70,592			62,271
Other		246			268			2,118			908

Net cash used in investing activities		(26,380	)		(120,329	)		(284,427	)		(1,157,326	)


Cash flows from financing activities
Distributions to partners		(52,781	)		(46,833	)		(158,302	)		(128,516	)
Net proceeds (costs) from equity offering		124,643			(219	)		124,643			577,743
Proceeds from issuance of senior notes		—			—			400,000			600,000
Proceeds from borrowings		70,000			108,000			360,000			359,000
Repayments of borrowings		(195,000	)		(5,000	)		(617,500	)		(365,000	)
Cash paid for debt issuance costs		(158	)		(617	)		(9,695	)		(19,206	)
Other		(437	)		—			(644	)		—

Net cash provided by (used in) financing activities		(53,733	)		55,331			98,502			1,024,021


Net increase (decrease) in cash and cash equivalents		(6,022	)		1,152			(6,812	)		1,487
Cash and cash equivalents – beginning of period		13,923			8,975			14,713			8,640

Cash and cash equivalents – end of period	$	7,901		$	10,127		$	7,901		$	10,127


Supplemental disclosure:
Cash paid for interest	$	4,709		$	5,806		$	54,039		$	29,632

Noncash investing activities:
Other assets acquired related to acquisition	$	—		$	—		$	—		$	4,827
Other liabilities assumed related to acquisition	$	—		$	(430	)	$	—		$	33,499
Special units issued as consideration in an acquisition	$	—		$	—		$	—		$	191,302

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

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


	Common Units					Class B Units				Special Units				Total

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

Unit-based compensation		105		2,352			—		—		—		—		2,352
Distributions paid		—		(158,302	)		1,474		—		—		—		(158,302	)
Issuance of units		5,500		124,507			—		—		—		—		124,507
Other		—		(607	)		—		—		—		—		(607	)
Net income		—		22,703			—		5,491		—		2,439		30,633


Balance at September 30, 2013		101,238	$	662,039			23,780	$	412,044		10,346	$	196,919	$	1,271,002


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

Balance at December 31, 2011		79,033	$	580,961			—		—		—		—	$	743		$	581,704
Unit-based compensation		113		3,648			—		—		—		—		—			3,648
Distributions paid		—		(128,516	)		461		—		—		—		—			(128,516	)
Issuance of units		9,009		177,743			21,379		400,000		10,346		191,302		—			769,045
Net Income (loss)		—		(75,310	)		—		7,814		—		3,744		—			(63,752	)
Other		—		(9	)		—		—		—		—		—			(9	)
Other comprehensive income (loss)		—		—			—		—		—		—		(523	)		(523	)


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

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

PVR PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 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, Ohio 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. 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 while no subsequent events have occurred that would require recognition in the Consolidated Financial Statements, there were subsequent events for which disclosure is required in the Notes to the Consolidated Financial Statements. See Note 12 to the Consolidated Financial Statements.

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

2.	Divestitures

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.

On August 19, 2013, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin. This Midcontinent Midstream investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million 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 Form10-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 September 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 September 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 September 30, 2013, Using
Description	Fair Value Measurements at September 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	$	229		$	—	$	229		$	—
Commodity derivative liabilities - current		(691	)	$	—		(691	)	$	—

Total	$	(462	)	$	—	$	(462	)	$	—

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 September 30, 2013 for commodities related to revenues:


	Average Volume Per Day			Weighted Average Swap Price			Fair Value at September 30, 2013

Crude oil swap		(barrels	)		(per barrel	)
Fourth quarter 2013		500		$	94.80		$	(309	)

Natural gas swaps		(MMBtu	)		(per MMBtu	)
Fourth quarter 2013		5,500		$	3.823			229

Propane swap - OPIS Conway		(gallons	)		(per gallon	)
Fourth quarter 2013		42,000		$	1.00875			(125	)

Settlements to be paid in subsequent period								(257	)

Interest Rate Swaps

During the nine months ended September 30, 2013, we did not have any open Interest Rate Swap positions. Therefore, there are no fair value measurements to disclose. As of September 30, 2012 we reported a gain in accumulated other comprehensive income (“AOCI”) of $0.2 million related to the Interest Rate Swaps. In connection with periodic settlements and related reclassification of other comprehensive income, we recognized $0.5 million of net hedging losses on the Interest Rate Swaps in the derivatives line on the Consolidated Statements of Operations during the nine months ended September 30, 2012. See the following “Financial Statement Impact of Derivatives” section for the impact of the Interest Rate Swaps on our Consolidated Financial Statements.

Financial Statement Impact of Derivatives

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


	Location of gain (loss)	Three Months Ended						Nine Months Ended
	on derivatives recognized	September 30,						September 30,
	in statement of operations	2013			2012			2013			2012
Derivatives not designated as hedging instruments:
Commodity contracts	Derivatives	$	(965	)	$	(1,695	)	$	(560	)	$	1,879
Interest rate contracts	Derivatives		—			171			—			322

Total increase (decrease) in net income resulting from derivatives		$	(965	)	$	(1,524	)	$	(560	)	$	2,201


Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	(123	)	$	(1,332	)	$	(98	)	$	(8,578	)
Unrealized derivative gains (losses)	Derivatives		(842	)		(192	)		(462	)		10,779

Total increase (decrease) in net income resulting from derivatives		$	(965	)	$	(1,524	)	$	(560	)	$	2,201

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 period presented:


		Fair Values as of September 30, 2013
	Balance Sheet Location	Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Commodity contracts	Derivative assets/liabilities - current		229		691

Total derivatives not designated as hedging instruments		$	229	$	691


Total fair value of derivative instruments		$	229	$	691

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

As of September 30, 2013, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of September 30, 2013, we did not own derivative instruments containing credit risk contingencies.

5.	Equity Investments

In accordance with the equity method of accounting, net of eliminations we recognized earnings from all equity investments in the aggregate of $0.9 million and $3.8 million for the nine months ended September 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 $6.5 million and $4.0 million for the nine months ended September 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.

As noted in Note 2Divestitures, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin. This Midcontinent Midstream investment had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues on the Consolidated Statement of Operations.

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:


	August 31,		November 30,
	2013		2012
Current assets	$	22,682	$	55,351
Noncurrent assets	$	111,288	$	273,158
Current liabilities	$	15,749	$	38,188
Noncurrent liabilities	$	1,720	$	3,933


	Nine Months Ended August 31,
	2013		2012
Revenues	$	34,447	$	42,772
Expenses	$	30,107	$	29,190
Net income	$	4,340	$	13,582

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) 5.50 to 1.0 commencing with the fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013; and (ii) 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 September 30, 2013, net of outstanding indebtedness of $332.5 million and letters of credit of $10.4 million, we had remaining borrowing capacity of $657.1 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2013 was approximately 3.4%. We do not have a public rating for the Revolver. As of September 30, 2013, we were in compliance with all covenants under the Revolver.

Senior Notes

In May 2013, we sold $400.0 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 or any guarantor of the Senior Notes to obtain funds from their subsidiaries by dividend or loan.

7.	Partners’ Capital and Distributions

As of September 30, 2013, partners’ capital consisted of 101.2 million common units, 10.3 million Special Units and 23.8 million Class B Units. We will pay distributions on November 13, 2013 with respect to the quarter ended September 30, 2013.

Equity Offering

In September 2013, we issued 5.5 million common units representing limited partner interest in PVR in a registered public offering. Total net proceeds of approximately $124.5 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $2.0 million, were used to repay a portion of the Revolver.

At The Market (“ATM”) Equity Program

An ATM program is an alternative way of raising capital by issuing equity through existing markets over a period of time. The flexibility of timing the issuance of units helps us to match demand for capital with the supply by controlling the number of units issued. Additionally, it reduces the volatility of unit price by avoiding issuance of a large number of common units. In August 2013 we issued our prospectus supplement relating to the issuance and sale from time to time of common units representing limited partner interests in PVR, or common units, having an aggregate offering price of up to $150.0 million through one or more sales agents. These sales, if any, will be made pursuant to the terms of the ATM equity offering sales agreement between us and the sales agents. The compensation of sales agents for the sales of common units shall not exceed 2.0% of the gross sales price per common unit. The net proceeds from any sales under this ATM program will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of September 30, 3013, no sales have been made under the ATM program.

Special Units

The Special Units convert to common units on the first business day after the record date for distributions with respect to the quarter ended September 30, 2013. Therefore, conversion of the Special Units to common units will occur on November 7, 2013. Absent an early conversion event, the Special Units will not be entitled to accrue distributions until the quarter commencing on October 1, 2013. If the Special Units would have been entitled to accrue and receive the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended September 30, 2013, we would pay an aggregate of $5.7 million in distributions to the holders of the Special Units on November 13, 2013.

Class B Units

We will pay distributions to the holders of the Class B Units with respect to the quarter ended September 30, 2013 by issuing an aggregate of 525,624 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 September 30, 2013, the amount of cash distributions that would have been attributable to the Class B Units was $13.1 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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)
Less:
Distributions to participating securities		(13,124	)		(11,814	)		(38,577	)		(17,534	)
Recognition of beneficial conversion feature (1)		(20,106	)		(17,120	)		(58,881	)		(28,174	)
Participating securities’ allocable share of undistributed net loss		6,621			3,969			21,898			14,109

Net income (loss) allocable to common units, basic and diluted	$	(8,721	)	$	13,818		$	(44,927	)	$	(95,351	)


Weighted average number of common units outstanding, basic and diluted		96,983			88,366			96,283			83,834

Net income (loss) per common unit, basic and diluted	$	(0.09	)	$	0.16		$	(0.47	)	$	(1.14	)

(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 income loss per common unit for the three and nine months ended September 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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012

Special units		10,346		10,346		10,346		5,173
Class B units		23,621		21,620		23,129		10,770
Phantom units		78		73		70		51

		34,045		32,039		33,545		15,994

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 nine months ended September 30, 2013, we paid cash distributions of $52.8 million and $158.3 million.

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

On November 13, 2013, we will pay a $0.55 per unit quarterly distribution to common unit holders of record on November 6, 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 nine months ended September 30, 2013, we granted 288 thousand phantom units at a weighted average grant-date fair value of $23.19 per unit including 186 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 nine months ended September 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 could vest ranges 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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Phantom units	$	1,092	$	939	$	2,891	$	4,196
Director deferred and common units		156		147		465		447

	$	1,248	$	1,086	$	3,356	$	4,643

9.	Commitments and Contingencies

Legal

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

Environmental Compliance

As of September 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 nine months ended September 30, 2013, 43% of our total consolidated revenues and 41% of our September 30, 2013 consolidated accounts receivable resulted from six of our natural gas midstream customers. Within the Eastern Midstream segment for the nine months ended September 30, 2013, 56% of the segment’s revenues and 53% of the September 30, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for the nine months ended September 30, 2013, 47% of the segment’s revenues and 39% of the September 30, 2013 accounts receivable for the segment resulted from three 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 September 30, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream 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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Consolidated Statements of Operations:
Other income	$	217	$	803	$	481	$	2,043
General and administrative	$	5	$	3	$	16	$	19


	September 30, 2013		December 31, 2012
Consolidated Balance Sheets:
Accounts receivable	$	5,001	$	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 September 30, 2013
Revenues	$	51,719	$	211,879		$	25,366	$	288,964
Cost of midstream gas purchased		—		163,824			—		163,824
Operating costs and expenses		8,204		16,650			6,054		30,908
Depreciation, depletion & amortization		25,355		15,719			6,059		47,133

Operating income	$	18,160	$	15,686		$	13,253	$	47,099

Interest expense									(28,358	)
Derivatives									(965	)
Other									112

Net income								$	17,888

Additions to property and equipment	$	65,701	$	19,049		$	4	$	84,754

Three Months Ended September 30, 2012
Revenues	$	26,800	$	207,522		$	34,525	$	268,847
Cost of midstream gas purchased		—		147,246			—		147,246
Operating costs and expenses		5,360		15,990			7,768		29,118
Depreciation, depletion & amortization		11,867		11,913			8,212		31,992

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

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

Net income								$	38,783

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

Nine Months Ended September 30, 2013
Revenues	$	141,054	$	599,889		$	84,897	$	825,840
Cost of midstream gas purchased		—		489,106			—		489,106
Operating costs and expenses		21,758		48,748			19,879		90,385
Depreciation, depletion & amortization		71,461		45,679			20,892		138,032

Operating income	$	47,835	$	16,356		$	44,126	$	108,317

Interest expense									(78,362	)
Derivatives									(560	)
Other									1,238

Net income								$	30,633

Additions to property and equipment	$	284,688	$	59,320		$	2,429	$	346,437

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

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

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

Net loss								$	(63,752	)

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


	Total assets
	September 30, 2013		December 31, 2012

Eastern Midstream	$	1,855,783	$	1,677,846
Midcontinent Midstream		589,420		640,437
Coal and Natural Resource Management		655,077		680,426

Totals	$	3,100,280	$	2,998,709

12.

Subsequent Events

On October 9, 2013, PVR, together with PVR GP, LLC, a Delaware limited liability company and PVR’s general partner (the “General Partner”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Regency Energy Partners LP, a Delaware limited partnership (“Regency”), RVP LLC, a Delaware limited liability company and a wholly owned subsidiary of Regency (“Merger Sub”) and Regency GP LP, a Delaware limited partnership and the general partner of Regency (“Regency GP”), pursuant to which PVR will merge with and into Merger Sub (the “Merger”), with PVR continuing its existence as the surviving entity of the merger. Upon the completion of the Merger, PVR will be a wholly-owned subsidiary of Regency. The board of directors of Regency’s managing general partner and the sole member of Merger Sub have unanimously approved the Merger Agreement, and the board of directors of PVR’s General Partner has unanimously approved and agreed to submit the Merger Agreement to a vote of the PVR unitholders and to recommend that the unitholders adopt the Merger Agreement.

Under the terms of the Merger Agreement, holders of PVR common units and Class B Units will receive 1.020 common units of Regency for each PVR unit outstanding immediately prior to the effective time of the Merger. In addition, PVR unitholders will receive a one-time cash payment at closing of the Merger estimated to be approximately $40.0 million in the aggregate. The consideration to be received by PVR unitholders is valued at $28.68 per common unit based on Regency’s closing price as of October 9, 2013, representing a 25.7% premium to the closing price of PVR’s common units of $22.81 on October 9, 2013.

The Merger Agreement is subject to customary closing conditions including, among other things, (i) approval of the Merger Agreement by PVR’s unitholders, (ii) receipt of applicable regulatory approvals, (iii) the effectiveness of a registration statement on Form S-4 with respect to the issuance of Regency common units to be issued in connection with the Merger, (iv) receipt of certain tax opinions, (v) approval for listing of the Regency common units to be issued in connection with the Merger on the New York Stock Exchange and (vi) conversion of the 10,346,257 Special Units outstanding as of the date of the Merger Agreement into an aggregate of 10,346,257 common units.

On October 16, 2013, 0.6 million additional common units were purchased by the underwriter pursuant to the September 2013 equity offering and the related option to purchase additional units. See a discussion of the 2013 equity offering in Note. 7.The net proceeds of the option exercise will be approximately $13.6 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $0.2 million. The net proceeds will be used to repay a portion of the Revolver.

In October 2013, the Board of Directors of PVR GP, LLC, the general partner of PVR, approved a plan to redeem up to $127.4 million of our 8.375% Senior Notes due in 2020 (the “Senior Notes”). This plan is revocable at our discretion until the trustee issues notification of a redemption to the holders of the Senior Notes. Using proceeds from borrowings under the Revolver, we expect to redeem the Senior Notes on December 1, 2013, resulting in a charge of approximately $14.0 million in the fourth quarter of 2013. The loss on extinguishment of debt would represent the difference between the reacquisition price on the portion of the Senior Notes redeemed, which includes any premium, and the net carrying amount of the Senior Notes.

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;

•

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;

•

our ability to complete our previously announced merger with Regency Energy Partners, L.P.;

•

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 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:

Regency Merger

Eastern Midstream

In September 2013, we announced that we entered into a definitive agreement to construct, own and operate a 45-mile natural gas trunkline and associated gathering pipelines and facilities servicing lean gas production in the Utica Shale in eastern Ohio. We expect the capital investment for the trunkline, initial gathering line, compression stations and dehydration facilities to be $125.0 to $150.0 million through 2015.

We invested approximately $235.0 million in the first nine months of 2013 constructing and expanding our existing 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 613 MMcfd in the third quarter of 2012 to 1,426 MMcfd in the third quarter of 2013.

Midcontinent Midstream

On August 19, 2013, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture in Wyoming’s Powder River Basin. The investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues on the Consolidated Statement of Operations.

Construction efforts were primarily concentrated in the Panhandle and Crescent systems, and well connects. We invested approximately $42.9 million during the nine months ended September 30, 2013 constructing gathering systems and compressor stations. Our average system volume decreased from 410 MMcfd in the third quarter of 2012 to 381 MMcfd in the third quarter of 2013 due to natural gas production declines, partially offset by increases related to recently completed construction projects and 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), propane and natural gas. We currently have four commodity derivatives, all of which expire at the end of 2013.

Equity Offering

In September 2013, PVR issued 5.5 million common units representing limited partner interest in PVR in a registered public offering. On October 16, 2013, the underwriter exercised its option to purchase 0.6 million additional common units. The combined proceeds of the September equity offering and the October exercise of the underwriter’s option will be approximately $138.1 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $2.2 million. The net proceeds will be used to repay a portion of the Revolver.

At The Market (“ATM”) Equity Program

Results of Operations

Consolidated Review

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues	$	288,964		$	268,847		$	825,840		$	738,176
Expenses		(241,865	)		(208,356	)		(717,523	)		(758,842	)

Operating income (loss)		47,099			60,491			108,317			(20,666	)
Other income (expense)		(29,211	)		(21,708	)		(77,684	)		(43,086	)

Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)

Eastern Midstream Segment

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


	Three Months Ended September 30,				Favorable			% Change Favorable
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Gathering fees	$	24,021	$	14,012	$	10,009			71	%
Trunkline fees		27,389		11,747		15,642			133	%
Other		309		1,041		(732	)		(70	%)

Total revenues		51,719		26,800		24,919			93	%


Expenses
Operating		3,190		2,124		(1,066	)		(50	%)
General and administrative		5,014		3,236		(1,778	)		(55	%)
Depreciation and amortization		25,355		11,867		(13,488	)		(114	%)

Total operating expenses		33,559		17,227		(16,332	)		(95	%)


Operating income	$	18,160	$	9,573	$	8,587			90	%


Operating Statistics
Gathered volumes (MMcfd)		622		444		178			40	%
Trunkline volumes (MMcfd)		804		169		635			376	%

Revenues

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

Expenses

Operating expenses increased due to prior and current years’ expansion projects. The related costs of these facilities have increased upon completion of projects and include increased field salaries, supplies, chemicals and lubricants.

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

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

Eastern Midstream Segment

Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 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:


	Nine Months Ended September 30,					Favorable			% Change Favorable
	2013			2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Gathering fees	$	71,162		$	28,316	$	42,846			151	%
Trunkline fees		70,143			28,394		41,749			147	%
Other		(251	)		2,687		(2,938	)		(109	%)

Total revenues		141,054			59,397		81,657			137	%


Expenses
Operating		8,045			4,211		(3,834	)		(91	%)
General and administrative		13,713			6,126		(7,587	)		(124	%)
Acquisition related costs		—			14,049		14,049			N/A
Depreciation and amortization		71,461			22,322		(49,139	)		(220	%)

Total operating expenses		93,219			46,708		(46,511	)		(100	%)


Operating income	$	47,835		$	12,689	$	35,146			277	%


Operating Statistics
Gathered volumes (MMcfd)		606			330		276			84	%
Trunkline volumes (MMcfd)		716			127		589			464	%

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 is due to lower management fees, net of related party eliminations, earned on the water line construction projects due to a slow-down in construction and completion of projects. The decrease in equity earnings from the joint venture relates to increased operational costs in 2013. The joint venture began operations in April 2012.

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 have increased upon completion of projects and include increased field salaries, supplies, chemicals and lubricants.

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 September 30, 2013 Compared with Three Months Ended September 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:


	Three Months Ended September 30,				Favorable			% Change Favorable
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	92,005	$	78,026	$	13,979			18	%
Natural gas liquids		104,585		96,237		8,348			9	%
Gathering fees		652		1,470		(818	)		(56	%)
Gain on sale of plant		—		31,292		(31,292	)		N/A
Other		14,637		497		14,140			2845	%

Total revenues		211,879		207,522		4,357			2	%


Expenses
Cost of gas purchased		163,824		147,246		(16,578	)		(11	%)
Operating		11,591		11,164		(427	)		(4	%)
General and administrative		5,059		4,826		(233	)		(5	%)
Depreciation and amortization		15,719		11,913		(3,806	)		(32	%)

Total operating expenses		196,193		175,149		(21,044	)		(12	%)


Operating income	$	15,686	$	32,373	$	(16,687	)		(52	%)


Operating Statistics
Daily throughput volumes (MMcfd)		381		410		(29	)		(7	%)

Revenues

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

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 27%, from $2.81 in the third quarter of 2012 to $3.58 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. As a consequence the NGL product contains less ethane. The rejected ethane shows up in the residue gas increasing the volume of natural gas available for sale. Partially offsetting the increase in higher natural gas prices was a decrease in throughput volumes primarily due to the natural decline of natural gas wells.

NGL and condensate revenues increased primarily due to higher NGL pricing. Our average realized price received for a Conway NGL barrel in the third quarter of 2013 was $34.81 compared to $29.53 for the same period of 2012. The increase was partially offset by a decrease in processed NGL volumes. 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 a decline in gathered volumes for the region and sale of the Crossroads plant.

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant for net proceeds of $62.3 million after transaction costs. A gain on sale of assets of $31.3 million was recognized in the third quarter of 2012.

Other revenues increased due to the August 19, 2013 sale of our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture in Wyoming’s Powder River Basin. This investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues in the third quarter of 2013.

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 $0.77, or 27%, from $2.81 in the third quarter of 2012 to $3.58 in the same period of 2013. Also, NGLs payments to producers increased due to the average Conway NGL barrel increasing by $5.28, or 18%, from $29.53 in the third quarter of 2012 to $34.81 in the same period of 2013.

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

Midcontinent Midstream Segment

Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 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:


	Nine Months Ended September 30,					Favorable			% Change Favorable
	2013		2012			(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Natural gas	$	282,830	$	215,780		$	67,050			31	%
Natural gas liquids		298,563		316,161			(17,598	)		(6	%)
Gathering fees		2,313		5,778			(3,465	)		(60	%)
Gain on sale of assets		—		31,292			(31,292	)		N/A
Other		16,183		2,042			14,141			693	%

Total revenues		599,889		571,053			28,836			5	%


Expenses
Cost of gas purchased		489,106		453,543			(35,563	)		(8	%)
Operating		32,519		31,642			(877	)		(3	%)
General and administrative		16,229		16,575			346			2	%
Impairments		—		124,845			124,845			N/A
Depreciation and amortization		45,679		37,220			(8,459	)		(23	%)

Total operating expenses		583,533		663,825			80,292			12	%


Operating income (loss)	$	16,356	$	(92,772	)	$	109,128			118	%


Operating Statistics
Daily throughput volumes (MMcfd)		385		435			(50	)		(12	%)

Revenues

Natural gas revenues increased primarily due to higher natural gas prices. The average New York Mercantile Exchange (NYMEX) natural gas spot price increased 42%, from $2.59 for the nine months ended September 30, 2012 to $3.67 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. As a consequence the NGL product contains less ethane. The rejected ethane shows up in the residue gas increasing the volume of natural gas available for sale. 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 and the natural decline of natural gas wells. The Crossroads plant processed approximately 36 MMcfd in the nine months ended September 30, 2012.

NGL and condensate revenues decreased primarily due to flat NGL pricing and lower ethane sales, being in ethane rejection mode. Our average realized price received for a Conway NGL barrel in the nine months ended September 30, 2013 was $34.56 compared to $33.64 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 $2.7 million. Gathering fees also decreased due to a decline in gathered volumes for the region.

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 $1.08, or 42%, from $2.59 in the nine months ended September 30, 2012 to $3.67 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. The increase was offset by the sale of the Crossroads plant at the beginning of July 2012. Property tax expense also increased based upon higher assessed asset values related to completed projects, such as Antelope Hills.

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 September 30, 2013 Compared with Three Months Ended September 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:


	Three Months Ended September 30,				Favorable			% Change Favorable
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	20,816	$	28,760	$	(7,944	)		(28	%)
Other		4,550		5,765		(1,215	)		(21	%)

Total revenues		25,366		34,525		(9,159	)		(27	%)


Expenses
Operating		2,725		4,299		1,574			37	%
General and administrative		3,329		3,469		140			4	%
Depreciation, depletion and amortization		6,059		8,212		2,153			26	%

Total expenses		12,113		15,980		3,867			24	%


Operating income	$	13,253	$	18,545	$	(5,292	)		(29	%)


Other data

Coal royalty tons		5,684		7,703		(2,019	)		(26	%)

Average coal royalties per ton	$	3.66	$	3.73	$	(0.07	)		(2	%)

Revenues

Coal royalties, which accounted for 82% of the Coal and Natural Resource Management segment revenues for the three months ended September 30, 2013 and 83% 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 related to coal service facilities decreased due to the decrease in coal production.

Expenses

Operating expenses decreased primarily due to a recoupment of property taxes from a bankrupt lessee and 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.

DD&A decreased from the comparative period due to the decrease in coal production and the related depletion expense.

Coal and Natural Resource Management Segment

Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 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:


	Nine Months Ended September 30,				Favorable			% Change Favorable
	2013		2012		(Unfavorable)			(Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	66,990	$	91,150	$	(24,160	)		(27	%)
Other		17,907		16,576		1,331			8	%

Total revenues		84,897		107,726		(22,829	)		(21	%)


Expenses
Operating		9,462		11,677		2,215			19	%
General and administrative		10,417		11,873		1,456			12	%
Depreciation, depletion and amortization		20,892		24,759		3,867			16	%

Total expenses		40,771		48,309		7,538			16	%


Operating income	$	44,126	$	59,417	$	(15,291	)		(26	%)


Other data

Coal royalty tons		19,023		23,584		(4,561	)		(19	%)

Average coal royalties per ton	$	3.52	$	3.86	$	(0.34	)		(9	%)

Revenues

Coal royalties, which accounted for 79% of the Coal and Natural Resource Management segment revenues for the nine months ended September 30, 2013 and 85% for the nine 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. Offsetting the increase was a reduction in other revenues related to coal service facilities, which decreased due to the decrease in coal production.

Expenses

General and administrative expenses decreased due to lower employee costs.

DD&A decreased from the comparative period due to 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Operating income (loss)	$	47,099		$	60,491		$	108,317		$	(20,666	)
Other income (expense)
Interest expense		(28,358	)		(20,288	)		(78,362	)		(45,616	)
Derivatives		(965	)		(1,524	)		(560	)		2,201
Other		112			104			1,238			329

Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
Source	2013			2012			2013			2012
Interest on Revolver and bank fees	$	(4,901	)	$	(5,345	)	$	(16,454	)	$	(15,322	)
Interest on Senior Notes		(25,250	)		(18,750	)		(66,433	)		(37,267	)
Debt issuance costs and other		(1,917	)		(1,589	)		(5,399	)		(4,217	)
Capitalized interest		3,710			5,396			9,924			11,190

Total interest expense	$	(28,358	)	$	(20,288	)	$	(78,362	)	$	(45,616	)

For the three months ended September 30, 2013 and 2012 the increase in interest expense was primarily due to the 6.5% Senior Notes issued in May 2013 for $400 million. For the nine months ended September 30, 2013 and 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. 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. Lower capitalized interest related to construction efforts in the Eastern Midstream and Midcontinent Midstream segments also increased interest expense for the comparable periods.

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, natural gas and natural gas liquid prices. We determine the fair values of our commodity derivative agreements using discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk for derivatives in a liability position. The fair value of our derivatives at September 30, 2013 was a current asset of $0.2 million and current liability of $0.7 million.

Our derivative activity for the periods presented is summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Natural gas midstream commodity realized derivative gain (loss)	$	(123	)	$	(918	)	$	(98	)	$	(7,365	)
Natural gas midstream commodity unrealized derivative gain (loss)		(842	)		(777	)		(462	)		9,244
Interest Rate Swap realized derivative loss		—			(414	)		—			(1,213	)
Interest Rate Swap unrealized derivative gain		—			384			—			1,012
Interest Rate Swap other comprehensive income reclass		—			201			—			523

Total derivative gain (loss)	$	(965	)	$	(1,524	)	$	(560	)	$	2,201
			��

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:


	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	30,633		$	(63,752	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities (summarized)		135,008			175,148
Net changes in operating assets and liabilities		13,472			23,396

Net cash provided by operating activities		179,113			134,792
Net cash used in investing activities (summarized)		(284,427	)		(1,157,326	)
Net cash provided by financing activities (summarized)		98,502			1,024,021

Net increase (decrease) in cash and cash equivalents	$	(6,812	)	$	1,487

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the nine months ended September 30, 2013 as compared to the same period in 2012 was primarily driven by increased fee-based revenues related to the Eastern Midstream segment, increased distributions received from our equity investments, a decrease in cash paid for acquisition related costs and derivative settlements. These favorable variance were partially offset by a decrease in coal royalties and 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:


	Nine Months Ended September 30,
	2013		2012
Eastern Midstream
Acquisitions (1)	$	—	$	1,040,564
Internal growth		235,030		234,803
Maintenance		1,757		1,019

Total		236,787		1,276,386


Midcontinent Midstream
Internal growth	$	42,904	$	84,458
Maintenance		10,018		11,168

Total		52,922		95,626


Coal and Natural Resource Management
Acquisitions	$	2,334	$	836
Internal growth		1		113
Maintenance		83		10

Total		2,418		959


Total capital expenditures	$	292,127	$	1,372,971

(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 $622.0 million to intangible assets and $70.3 million to goodwill.

Excluding the Chief Acquisition, our Eastern Midstream and Midcontinent Midstream segments’ capital expenditures for the nine months ended September 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 nine months ended September 30, 2013, we issued 5.5 million common units representing limited partner interest in PVR in a registered public offering. Total net proceeds of approximately $124.5 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $2.0 million, were used to repay a portion of the Revolver. We also 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 nine months ended September 30, 2013, we repaid borrowings of $617.5 million. During the same period we incurred borrowings of $360.0 million to fund our natural gas midstream capital expenditures and other working capital needs. During the nine months ended September 30, 2012, we received funds from the issuance of $600 million in Senior Notes and $577.7 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 nine months ended September 30, 2013 and 2012, we paid cash distributions to our unitholders of $158.3 million and $128.5 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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Reconciliation of Non-GAAP “Total Segment Adjusted EBITDA” to GAAP “Net income (loss)”:

Segment Adjusted EBITDA (a):
Eastern Midstream	$	43,515		$	21,440		$	119,296		$	49,060
Midcontinent Midstream		17,103			12,994			47,733			38,001
Coal and Natural Resource Management		19,312			26,757			65,018			84,176

Total segment adjusted EBITDA	$	79,930		$	61,191		$	232,047		$	171,237
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(47,133	)		(31,992	)		(138,032	)		(84,301	)
Impairments on PP&E		—			—			—			(124,845	)
Acquisition related costs		—			—			—			(14,049	)
Gain on sale of assets		14,302			31,292			14,302			31,292
Interest expense		(28,358	)		(20,288	)		(78,362	)		(45,616	)
Derivatives		(965	)		(1,524	)		(560	)		2,201
Other		112			104			1,238			329

Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Distributable cash flow”:
Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)
Depreciation, depletion and amortization		47,133			31,992			138,032			84,301
Impairments on PP&E		—			—			—			124,845
Acquisition related costs		—			—			—			14,049
Gain on sale of assets		(14,302	)		(31,292	)		(14,302	)		(31,292	)
Derivative contracts:
Derivative (gains) losses included in net income		965			1,524			560			(2,201	)
Cash receipts (payments) to settle derivatives for the period		(123	)		(1,332	)		(313	)		(8,578	)
Equity earnings from joint ventures, net of distributions		1,961			697			5,635			142
Maintenance capital expenditures		(4,044	)		(3,749	)		(11,858	)		(12,197	)


Distributable cash flow (b)	$	49,478		$	36,623		$	148,387		$	105,317

(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, minus gain on sale of assets, plus interest expense, plus (minus) derivative gains (losses) 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, minus gain on sale of assets, 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

At The Market (“ATM”) Equity Program

we issued our prospectus supplement relating to the issuance and sale from time to time of common units representing limited partner interests in PVR, or common units, having an aggregate offering price of up to $150.0 million through one or more sales agents. These sales, if any, will be made pursuant to the terms of the ATM equity offering sales agreement between us and the sales agents. The compensation of sales agents for the sales of common units shall not exceed 2.0% of the gross sales price per common unit. The net proceeds from any sales under this ATM program will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of September 30, 3013, no sales have been made under the ATM program.

Equity Offering

Long-Term Debt

Revolver. As of September 30, 2013, net of outstanding indebtedness of $332.5 million and letters of credit of $10.4 million, we had remaining borrowing capacity of $657.1 million on the Revolver. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2013 was approximately 3.4%. We do not have a public rating for the Revolver. As of September 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 then ended, of not more than (i) 5.50 to 1.0 commencing with the fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013; and (ii) 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 $400.0 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 September 30, 2013, our remaining borrowing capacity under the $1.0 billion Revolver of approximately $657.1 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 $350.0-$400.0 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 September 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. Our current derivative financial instruments include swaps for crude oil (to hedge condensate volumes), propane and natural gas. The propane swap was added in the third quarter covering the period of September 1 through December 31, 2013. We currently have four commodity derivatives, all of which expire at the end of 2013.

At September 30, 2013, we reported a commodity derivative asset of $0.2 million and a commodity derivative liability of $0.7 million related to the Midcontinent Midstream segment. All four of our commodity derivatives reside 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 nine months ended September 30, 2013 we reported a net loss for our commodity hedges of $0.5 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 September 30, 2013

Crude oil swap		(barrels	)		(per barrel	)
Fourth quarter 2013		500		$	94.80		$	(309	)

Natural gas swaps		(MMBtu	)		(per MMBtu	)
Fourth quarter 2013		5,500		$	3.823			229

Propane swap - OPIS Conway		(gallons	)		(per gallon	)
Fourth quarter 2013		42,000		$	1.00875			(125	)

Settlements to be paid in subsequent period								(257	)

Net derivative liability							$	(462	)

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 $0.2 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 $0.5 million. We estimate that a $0.05 per gallon change in propane price would change the fair value of our propane swap by $0.2 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 $4.7 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 $4.2 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 $0.5 million. The crude oil hedge described above would reduce the net impact to $0.2 million.

For every $0.05 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 $0.7 million while operating in ethane rejection. Finally, for every $0.05 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 $0.4 million. The propane hedge described above would reduce the net impact to $0.2 million.

Interest Rate Risk

At September 30, 2013, we had no open derivative contracts related to interest rates. As of September 30, 2013, we had $332.5 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, $332.5 million, or 20%, 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 September 30, 2013 would cost us approximately $3.3 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 September 30, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment.

Item 4

Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 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 September 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, and Part I, Item 1A of the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 filed on July 29, 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 and Quarterly Report in Form 10-Q represent our currently known material risks.

Risks Related to Our Proposed Merger with Regency

We and Regency may be unable to obtain the regulatory clearances required to complete the merger or, in order to do so, we and Regency may be required to comply with material restrictions or satisfy material conditions.

Our proposed merger with Regency is subject to review by the Antitrust Division of the Department of Justice and the Federal Trade Commission under the Hart Scott Rodino Antitrust Improvements Act of 1976, which is referred to as the HSR Act, and potentially by state regulatory authorities. The closing of the merger is subject to the condition that there is no law, injunction, judgment, or ruling by a governmental authority in effect enjoining, restraining, preventing, or prohibiting the merger contemplated by the merger agreement. We can provide no assurance that all required regulatory clearances will be obtained. If a governmental authority asserts objections to the merger, Regency may be required to divest some assets in order to obtain antitrust clearance. There can be no assurance as to the cost, scope or impact of the actions that may be required to obtain antitrust approval. In addition, the merger agreement provides that Regency is not required to commit to dispositions of assets in order to obtain regulatory clearance unless they do not exceed specified thresholds. If Regency must take such actions, it could be detrimental to the combined organization following the consummation of the merger. Furthermore, these actions could have the effect of delaying or preventing completion of the proposed merger or imposing additional costs on or limiting the revenues of the combined organization following the consummation of the merger.

Even if the parties receive early termination of the statutory waiting period under the HSR Act or the waiting period expires, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest at any time, including after completion of the transaction. In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the transaction, before or after it is completed. Regency may not prevail and may incur significant cost in defending or settling any action under the antitrust laws.

Pending the completion of the transaction, our business and operations could be materially adversely affected.

Under the terms of our merger agreement with Regency, we are subject to certain restrictions on the conduct of our business prior to completing the transaction, which may adversely affect our ability to execute certain of our business strategies without first obtaining consent from Regency, including our ability in certain cases to enter into contracts, incur capital expenditures or grow our business. The merger agreement also restricts our ability to solicit, initiate or encourage alternative acquisition proposals with any third party and may deter a potential acquirer from proposing an alternative transaction or may limit our ability to pursue any such proposal. Such limitations could negatively affect our business and operations prior to the completion of the proposed transaction. Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on us.

In connection with the pending merger, it is possible that some customers, suppliers and other persons with whom we have business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the transaction, which could negatively affect our revenues, earnings and cash flows, as well as the market price of our common units, regardless of whether the transaction is completed.

We will incur substantial transaction-related costs in connection with the merger.

We expect to incur a number of non-recurring merger-related costs associated with completing the merger, combining the operations of the two companies, and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our and Regency’s businesses. There can be no assurance

that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.

Failure to successfully combine the businesses of PVR and Regency in the expected time frame may adversely affect the future results of the combined organization, and, consequently, the value of the Regency common units that PVR unitholders receive as the merger consideration.

The success of the proposed merger will depend, in part, on the ability of Regency to realize the anticipated benefits and synergies from combining the businesses of Regency and PVR. To realize these anticipated benefits, the businesses must be successfully combined. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Failure to complete the merger, or significant delays in completing the merger, could negatively affect the trading price of our common units and our future business and financial results.

Completion of the merger is not assured and is subject to risks, including the risks that approval of the merger by our unitholders or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the merger is not completed, or if there are significant delays in completing the merger, it could negatively affect the trading price of our common units and our future business and financial results, and we will be subject to several risks, including the following:

•

liability for damages to Regency under the terms and conditions of the merger agreement;

•

negative reactions from the financial markets, including declines in the price of our common units due to the fact that current prices may reflect a market assumption that the merger will be completed;

•

having to pay certain significant costs relating to the merger, including a termination fee of $134.5 million; and

•

the attention of our management will have been diverted to the merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

We may have difficulty attracting, motivating and retaining executives and other employees in light of the merger.

Uncertainty about the effect of the merger on PVR employees may have an adverse effect on us and the combined organization. This uncertainty may impair our ability to attract, retain and motivate personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may feel uncertain about their future roles with the combined organization. In addition, we may have to provide additional compensation in order to retain employees. If our employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined organization, the combined organization’s ability to realize the anticipated benefits of the merger could be reduced. Also, if we fail to complete the merger, it may be difficult and expensive to recruit and hire replacements for such employees.

Item 6

Exhibits


Exhibit Number	Exhibit Description	Filed Herewith	Furnished Herewith

1.1	ATM Equity Offering Sales Agreement, dated August 23, 2013, by and among PVR Partners, L.P., PVR GP, LLC, PVR Finco LLC, Merrill Lynch, Pierce, Fenner & Smith, Incorporated and RBS Securities Inc. (incorporated by reference to Exhibit 1.1 to Registrant’s Current Report on Form 8-K filed on August 23, 2013).

1.2	Underwriting Agreement, dated September 13, 2013, among PVR Partners, L.P., PVR GP, LLC, PVR Finco LLC and Barclays Capital Inc. (incorporated by reference to Exhibit 1.1 to Registrant’s Current Report on Form 8-K filed on September 17, 2013).

2.1	Agreement and Plan of Merger, dated as of October 9, 2013, by and among Regency Energy Partners LP, RVP LLC, Regency GP LP, PVR Partners, L.P. and PVR GP, LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K), (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on October 10, 2013).

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

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

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