PVR PARTNERS, L. P. - FORM 8-K - EX-99.1

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8-K - FORM 8-K - PVR PARTNERS, L. P.	d573103d8k.htm

Exhibit 99.1

News Release

Three Radnor Corporate Center, Suite 301

100 Matsonford Road

Radnor, PA 19087

FOR IMMEDIATE RELEASE

PVR PARTNERS ANNOUNCES SECOND QUARTER 2013 RESULTS

AND DECLARES CASH DISTRIBUTION

RADNOR, PA – July 24, 2013… PVR Partners, L.P. (NYSE: PVR) (“PVR”) today reported financial and operational results for the three months ended June 30, 2013. In addition, PVR declared a quarterly distribution of $0.55 per unit.

Second Quarter Results

Second quarter 2013 highlights and results, with comparisons to results for the second quarter of 2012 (“last year”) and the first quarter of 2013 (“last quarter”), included the following:

•

Adjusted EBITDA of $76.1 million as compared to $57.0 million last year and $76.0 million last quarter.

•

Distributable Cash Flow (“DCF”) of $49.0 million as compared to $32.9 million last year and $49.9 million last quarter.

•

Average daily natural gas throughput volumes of 1.7 billion cubic feet per day (“Bcfd”) as compared with 0.9 Bcfd last year and 1.6 Bcfd last quarter.

Adjusted EBITDA and DCF are not Generally Accepted Accounting Principles (“GAAP”) measures. Definitions and reconciliations of these non-GAAP measures to GAAP reporting measures appear in the financial tables which follow.

Quarterly Distribution

The Board of Directors of PVR GP, LLC, the general partner of PVR, declared a quarterly distribution of $0.55 per unit payable in cash on August 14, 2013 to common unitholders of record at the close of business on August 7, 2013. This distribution equates to an annualized rate of $2.20 per unit, which is unchanged from the distribution paid with respect to the first quarter of 2013 and represents a 3.8% increase over the distribution paid with respect to the second quarter of 2012.

Management Comment

“Our second quarter results were consistent with our first quarter performance, and significantly ahead of last year’s second quarter results,” said Bill Shea, President and CEO of PVR’s general partner. “However, results for the second quarter were below our expectations primarily due to producers delaying well connections in our Eastern Midstream operations. Some wells originally scheduled for connection in the second quarter have been delayed until later this year resulting in lower second quarter throughput volumes. These delays have negatively impacted our 2013 revenue projections and we have adjusted our 2013 guidance to reflect the financial impact on our full year results.

“Our continued belief in the long-term prospects for our Eastern Midstream operations is


PVR Reports Second Quarter 2013 Results		Page 2

supported by strong results from the wells that have been drilled and completed within our areas of operations, the continuing level of drilling activity within the region, and the overall scope and scale of the future drilling plans communicated by producers,” continued Mr. Shea. “However, changes in producers’ detailed schedules can materially impact volume and revenue growth on a quarter to quarter basis. Based on the revised well connection schedules most recently provided by producers, we expect total average daily Eastern Midstream throughput volumes at year end will be in the range of 1.6 to 1.8 Bcfd.”

Eastern Midstream Segment Results

The Eastern Midstream Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:

•

Adjusted EBITDA of $38.1 million as compared to $17.7 million last year and $37.7 million last quarter, primarily due to the continued development of internal growth projects and the acquisition of Chief Gathering LLC.

•

Quarterly average throughput volumes of 1.3 Bcfd as compared to 0.5 Bcfd last year and 1.2 Bcfd last quarter, reflecting growth on PVR’s existing systems, as well as the acquisition and expansion of the Chief Gathering systems.

Midcontinent Midstream Segment Results

The Midcontinent Midstream Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:

•

Adjusted EBITDA of $14.9 million as compared to $12.7 million last year and $15.7 million last quarter.

•

Quarterly average throughput volumes of 382 MMcfd as compared to 453 MMcfd last year and 391 MMcfd last quarter. Second quarter 2012 volumes included approximately 52 MMcfd attributable to the Crossroads system that was sold on July 3, 2012.

Coal and Natural Resource Management Segment Results

The Coal and Natural Resource Management Segment reported second quarter 2013 results, with comparisons to second quarter 2012 results and the first quarter of 2013, as follows:

•

Adjusted EBITDA of $23.1 million as compared to $26.7 million last year and $22.7 million last quarter. The year-over-year decline was primarily due to decreased coal production and pricing.

•

Coal royalty tons of 6.9 million tons as compared to 7.8 million tons last year and 6.4 million tons last quarter.

•

Coal royalties revenue of $23.2 million, or $3.37 per ton, as compared to $29.2 million, or $3.76 per ton last year and $23.0 million or $3.56 per ton last quarter.

Second quarter 2013 coal segment revenue included a $2.3 million one-time recognition of forfeitures of minimum payments from a lessee declaring bankruptcy.


PVR Reports Second Quarter 2013 Results		Page 3

Capital Investment and Resources

We invested $110.9 million on internal growth projects in our midstream businesses during the second quarter of 2013, of which $97.5 million was invested in the Eastern Midstream Segment.

On May 9^th, PVR closed a $400 million offering of Senior Notes. The net proceeds from the offering were used to repay a portion of the borrowings outstanding under PVR’s $1.0 billion revolving credit facility. As of June 30, 2013, we had borrowings of $457.5 million under our revolving credit facility, with remaining borrowing capacity thereunder of $532.1 million after adjusting for outstanding letters of credit.

Expansion Projects Update

The development and build-out of important growth projects in the Marcellus, Utica, Cline and Mississippian Lime continued during the second quarter of 2013.

•

Construction of the new “Severcool” compressor facility and central delivery point on the Wyoming County trunkline was completed and began operation during June. Completion of these facilities added 85 MMcfd of firm volume commitment to the Wyoming trunkline beginning July 1, 2013.

•

The new interconnection into the Wyoming trunkline for Carrizo Oil & Gas and Reliance Group began service during June.

•

The second phase of the new Lycoming gathering system, for which Inflection Energy is the primary shipper, was completed and began service in the second quarter. Work on additional phases of this system continues.

•

Completion of 13 new well connections in the Eastern Midstream Segment during the second quarter.

•

Construction of the initial phase of our gathering system in Greene County, Pennsylvania has been completed. Volume on the system during the second quarter averaged 12 MMcfd.

•

Early phase development work continues on a proposed new trunkline and gathering system in the Utica shale.

•

Completion of 52 new well connections in the Midcontinent Midstream Segment during the second quarter.

Financial Guidance for 2013

Based on current expectations, management has updated its Adjusted EBITDA guidance for 2013. Full year 2013 Adjusted EBITDA for the Eastern Midstream Segment is now expected to be in the range of $160 to $185 million and the Midcontinent Midstream Segment is now expected to be in the range of $60 to $70 million. Adjusted EBITDA for the Coal and Natural Resource Management Segment in the range of $75 to $85 million remains unchanged. Management now anticipates that full year 2013 maintenance capital expenditures will be in the range of $13 to $15 million. PVR’s expectation for full year 2013 internal growth capital in the range of $350 to $400 million remains unchanged.

PVR’s financial guidance is based on numerous assumptions about future events and conditions and, therefore, could vary materially from actual results. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision for acquisitions or operating environment changes. Adjusted EBITDA is a non-GAAP measure; reconciliations of non-GAAP measures to GAAP reporting measures appear in the financial


PVR Reports Second Quarter 2013 Results		Page 4

tables which follow.

Second Quarter 2013 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss second quarter 2013 financial and operational results, is scheduled for Wednesday, July 24, 2013 at 2:00 p.m. Eastern Daylight Time. Prepared remarks by members of company management will be followed by a question and answer period. Interested parties may listen via webcast at http://www.videonewswire.com/event.asp?id=94745 or by logging on using the link posted on our website, www.pvrpartners.com. Participants who would like to ask questions may join the conference via phone by dialing 800-860-2442 (international 412-858-4600) five to ten minutes before the scheduled start of the conference call (reference the PVR Partners call). An on-demand replay of the webcast will be available on our website shortly after the conclusion of the call. A telephonic replay of the call will be available through July 31 by dialing 877-344-7529 (international: 412-317-0088) and using conference playback number 10030534.

******

PVR Partners, L.P. (NYSE: PVR) is a publicly traded limited partnership which owns and operates a network of natural gas midstream pipelines and processing plants, and owns and manages coal and natural resource properties. Our midstream assets, located principally in Texas, Oklahoma and Pennsylvania, provide gathering, transportation, compression, processing, dehydration and related services to natural gas producers. Our coal and natural resource properties, located in the Appalachian, Illinois and San Juan basins, are leased to experienced operators in exchange for royalty payments. More information about PVR is available on our website at www.pvrpartners.com.

******

This release is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b). Brokers and nominees should treat one hundred percent (100.0%) of the Partnership’s distributions to non-U.S. investors as being attributable to income that is effectively connected with a United States trade or business. Accordingly, the Partnership’s distributions to non-U.S. investors are subject to federal income tax withholding at the highest applicable effective tax rate.

******

This press release includes “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Partnership’s ability to control or predict, which could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, regulatory, economic and market conditions, our ability realize the anticipated benefits from the acquisition of Chief Gathering LLC, the timing and success of business development efforts and other uncertainties. 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 and most recently filed Quarterly Reports on Form 10-Q. 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.


Contact:		Stephen R. Milbourne
		Director - Investor Relations
		Phone: 610-975-8204
		E-Mail: invest@pvrpartners.com

PVR PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited

(in thousands, except per unit data)


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

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


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

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


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

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

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


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

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

Weighted average number of Class B units outstanding		23,136			10,572			22,879			5,286
Weighted average number of Special units outstanding		10,346			5,116			10,346			2,558

Other data by segment:

Eastern Midstream:
Gathered volumes (MMcfd)		612			336			598			273
Trunkline volumes (MMcfd) (1)		698			120			671			106
Midcontinent Midstream:
Daily throughput volumes (MMcfd)		382			453			387			448
Coal and Natural Resource Management:
Coal royalty tons (in thousands)		6,893			7,776			13,339			15,881

(1)	Trunkline volumes include a significant portion of gathered volumes.

PVR PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)


	June 30,		December 31,
	2013		2012

Assets
Cash and cash equivalents	$	13,923	$	14,713
Accounts receivable		132,669		133,546
Assets held for sale		—		11,450
Derivative assets		425		—
Other current assets		5,368		5,446

Total current assets		152,385		165,155
Property, plant and equipment, net		2,124,764		1,989,346
Other long-term assets		840,661		844,208

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


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

Total current liabilities		149,145		200,822
Other long-term liabilities		30,400		35,468
Senior notes		1,300,000		900,000
Revolving credit facility		457,500		590,000
Partners’ capital		1,180,765		1,272,419

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Cash flows from operating activities
Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		46,113			28,456			90,899			52,309
Impairments		—			—			—			124,845
Commodity derivative contracts:
Total derivative gains included in net income		(846	)		(8,676	)		(405	)		(3,725	)
Cash receipts (payments) to settle derivatives for the period		32			(3,605	)		(190	)		(7,246	)
Non-cash interest expense		1,830			1,579			3,482			2,628
Non-cash unit-based compensation		844			1,519			2,108			3,557
Equity earnings, net of distributions received		2,349			186			3,674			(555	)
Other		(1,064	)		(51	)		(3,068	)		(698	)
Changes in operating assets and liabilities		(29,159	)		(3,742	)		(4,223	)		62

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


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

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


Cash flows from financing activities
Distributions to partners		(52,786	)		(41,265	)		(105,521	)		(81,683	)
Net proceeds from equity offering		—			577,962			—			577,962
Proceeds from issuance of senior notes		400,000			600,000			400,000			600,000
Proceeds from borrowings, net		(242,500	)		(185,000	)		(132,500	)		(109,000	)
Cash paid for debt issuance costs		(8,658	)		(18,589	)		(9,537	)		(18,589	)
Other		(112	)		—			(207	)		—

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


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

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

PVR PARTNERS, L.P.

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)


	Three Months Ended						Six Months Ended						Guidance Range
	June 30,						June 30,						Full Year 2013
	2013			2012			2013			2012			Low			High
Reconciliation of Non-GAAP “Total Segment Adjusted EBITDA” to GAAP “Net income (loss)”:

Segment Adjusted EBITDA (a):
Eastern Midstream	$	38,090		$	17,659		$	75,781		$	27,620		$	160,000		$	185,000
Midcontinent Midstream		14,926			12,684			30,630			25,007			60,000			70,000
Coal and Natural Resource Management		23,053			26,697			45,706			57,419			75,000			85,000

Total segment adjusted EBITDA	$	76,069		$	57,040		$	152,117		$	110,046		$	295,000		$	340,000
Adjustments to reconcile total Segment Adjusted EBITDA to Net income (loss)
Depreciation, depletion and amortization		(46,113	)		(28,456	)		(90,899	)		(52,309	)		(180,000	)		(190,000	)
Impairments on PP&E		—			—			—			(124,845	)		—			—
Acquisition related costs		—			(14,049	)		—			(14,049	)		—			—
Interest expense		(26,326	)		(15,511	)		(50,004	)		(25,328	)		(95,000	)		(100,000	)
Derivatives		846			8,676			405			3,725			—			—
Other		1,032			109			1,126			225			—			—

Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)	$	20,000		$	50,000


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


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


Distribution to Partners:

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


Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Net income as adjusted”:
Net income (loss)	$	5,508		$	7,809		$	12,745		$	(102,535	)
Impairments on PP&E and equity investments		—			—			—			124,845
Acquisition related costs		—			14,049			—			14,049
Adjustments for derivatives:
Derivative gains included in net income		(846	)		(8,676	)		(405	)		(3,725	)
Cash receipts (payments) to settle derivatives for the period		32			(3,605	)		(190	)		(7,246	)


Net income, as adjusted (c)	$	4,694		$	9,577		$	12,150		$	25,388

(a)

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

(b)

Distributable cash flow represents net income plus DD&A, plus impairments, plus acquisition related costs, plus (minus) derivative losses (gains) included in net income, plus (minus) cash received (paid) for derivative settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures. At management’s discretion, a fixed amount of $1.8 million per quarter in 2013 and $1.3 million per quarter in 2012 has been included in maintenance capital for well connects. 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.

(c)

Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash impairment charges, one-time charges related to acquisitions and changes in the fair value of derivatives. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. We use this information for comparative purposes within the industry. Net income, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

PVR PARTNERS, L.P.

QUARTERLY SEGMENT INFORMATION - unaudited

(in thousands)


	Eastern Midstream
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues
Gathering fees	$	25,003		$	9,385		$	47,141		$	14,304
Trunkline fees		21,653			10,255			42,754			16,647
Other		(1,218	)		1,484			(560	)		1,646

Total revenues		45,438			21,124			89,335			32,597

Expenses
Operating		2,875			1,189			4,855			2,087
General and administrative		4,473			2,276			8,699			2,890
Acquisition related costs		—			14,049			—			14,049
Depreciation, depletion and amortization		23,462			8,394			46,106			10,455

Total expenses		30,810			25,908			59,660			29,481


Operating income (loss)	$	14,628		$	(4,784	)	$	29,675		$	3,116


	Midcontinent Midstream
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues
Natural gas	$	103,111		$	63,127		$	190,825		$	137,754
Natural gas liquids		93,470			102,130			193,978			219,924
Gathering fees		883			1,764			1,661			4,308
Other		403			928			1,546			1,545

Total revenues		197,867			167,949			388,010			363,531

Expenses
Cost of gas purchased		167,074			140,833			325,282			306,297
Operating		10,574			9,251			20,928			20,478
General and administrative		5,293			5,181			11,170			11,749
Impairments		—			—			—			124,845
Depreciation, depletion and amortization		15,054			11,700			29,960			25,307

Total expenses		197,995			166,965			387,340			488,676


Operating income (loss)	$	(128	)	$	984		$	670		$	(125,145	)


	Coal and Natural Resource Management
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues
Coal royalties	$	23,223		$	29,231		$	46,174		$	62,390
Coal services		848			1,391			2,009			2,630
Timber		1,686			1,354			3,118			2,873
Oil and gas royalties		692			505			1,347			1,188
Other		3,711			1,358			6,883			4,120

Total revenues		30,160			33,839			59,531			73,201

Expenses
Operating		3,701			3,600			6,737			7,378
General and administrative		3,406			3,542			7,088			8,404
Depreciation, depletion and amortization		7,597			8,362			14,833			16,547

Total expenses		14,704			15,504			28,658			32,329


Operating income	$	15,456		$	18,335		$	30,873		$	40,872

PVR PARTNERS, L.P.

DERIVATIVE CONTRACT SUMMARY - unaudited

As of June 30, 2013


	Average Volume Per Day		Swap Price
Crude oil swap (WTI)	(barrels)		(per barrel)
Third quarter through the fourth quarter 2013		500	$	94.80

Natural gas swaps ⁽¹⁾	(MMBtu)		(per MMBtu)
Third quarter through the fourth quarter 2013		5,500	$	3.823

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

We anticipate operating our plants in “ethane rejection” for the remainder of 2013. Under this operational mode, we estimate that for every $1.00 per MMBtu change in the natural gas price, our natural gas midstream gross margin and operating income for the remainder of 2013 would change by $7.8 million, excluding the effect of the natural gas hedges described above, and all other factors remaining constant. The natural gas hedges described above would reduce the net impact to $6.8 million.

Similarly, for every $5.00 per barrel change in crude oil prices, with all other factors remaining constant, and excluding the effect of the 2013 crude oil derivative described above, we estimate that our natural gas midstream gross margin and operating income would change by $1.4 million. The crude oil hedge described above would reduce the net impact to $0.9 million.

For every $0.10 per gallon increase in the price of ethane with all other factors remaining constant, we estimate that our gross margin and operating income will decrease by $1.6 million while operating in ethane rejection. Finally, for every $0.10 per gallon increase in the price of other NGLs with all other factors remaining constant, we estimate that our gross margin and operating income will increase by $1.3 million.

⁽¹⁾

The natural gas swaps settle against the monthly index price reported in Inside FERC’s Natural Gas Market Report for Southern Star Central Gas Pipeline (Texas, Oklahoma, Kansas), which has historically tended to be settled at a lower price than the Henry Hub national benchmark. A significant portion of our physical gas sales are also priced using this reported monthly index.

PVR PARTNERS, L.P.

OPERATING STATISTICS

($ Amounts in 000s)


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

Volumes (MMcfd)
Lycoming Trunkline		340		120		338		106
Wyoming Trunkline		358		—		333		—

Total Trunkline Volume		698		120		671		106


Lycoming Gathering		238		138		230		115
Wyoming Gathering		189		145		190		132
East Lycoming Gathering		122		44		120		22
Bradford Gathering		52		7		50		4
Greene Gathering		12		2		8		1

Total Gathering		612		336		598		273

Total Throughput		1,310		456		1,269		379


Total Trunkline Fees	$	21,653	$	10,255	$	42,754	$	16,647
Total Gathering Fees	$	25,003	$	9,385	$	47,141	$	14,304

Trunkline Fees / Mcf	$	0.34	$	0.94	$	0.35	$	0.86
Gathering Fees / Mcf	$	0.45	$	0.31	$	0.44	$	0.29

MIDCONTINENT MIDSTREAM

Volumes (MMcfd)
Panhandle System		328		351		334		343
Crossroads System⁽¹⁾		—		52		—		55
Crescent System		31		24		29		23
Hamlin System		6		7		6		7

Total Processing Systems		365		434		369		428

Arkoma System		9		9		9		10
North Texas System		8		9		8		10

Total Gathering Only Systems		17		19		18		20

Total All Systems		382		453		387		448


Total Gathering and Processing Fees, Net⁽²⁾	$	30,390	$	26,188	$	61,182	$	55,689

Fees Per Mcf	$	0.87	$	0.64	$	0.87	$	0.68

⁽¹⁾	Crossroads System was sold July 3, 2012

⁽²⁾	Processing fees include revenues from natural gas, natural gas liquids and gathering fees less cost of gas purchased


COAL PRODUCTION

Coal royalty tons by region (000s)
Central Appalachia		2,784		3,476		5,401		7,544
Northern Appalachia		1,231		1,100		2,007		1,898
Illinois Basin		658		962		1,329		2,099
San Juan Basin		2,220		2,238		4,602		4,340

Total Tons		6,893		7,776		13,339		15,881


Total Coal Royalties	$	23,223	$	29,231	$	46,174	$	62,390


Average Coal Royalty per ton	$	3.37	$	3.76	$	3.46	$	3.93

PVR PARTNERS, L. P. - FORM 8-K - EX-99.1 - July 24, 2013

Attached files

PVR PARTNERS, L. P. Reports