PVR Partners, L. P. (PVR) 8-K PVR Partners Announces Third Quarter 2013 Results

Exhibit 99.1

         News Release   Three Radnor Corporate Center, Suite 301 100 Matsonford Road Radnor, PA 19087

FOR IMMEDIATE RELEASE

PVR PARTNERS ANNOUNCES THIRD QUARTER 2013 RESULTS

AND DECLARES CASH DISTRIBUTION

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

Third Quarter Results

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

• Adjusted EBITDA of $79.9 million as compared to $61.2 million last year and $76.1 million last quarter.

• Distributable Cash Flow (“DCF”) of $49.5 million as compared to $36.6 million last year and $49.0 million last quarter.

• Average daily natural gas throughput volumes of 1.8 billion cubic feet per day (“Bcfd”) as compared with 1.0 Bcfd last year and 1.7 Bcfd last quarter.

In addition, on August 19 PVR sold its 25% membership interest in Thunder Creek Gas Services, L.L.C. for $58.6 million which resulted in a reported gain of $14.3 million. The $14.3 million gain is included in Other Revenue and has been subtracted from the calculation of Adjusted EBITDA and DCF.

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 November 13, 2013 to common unitholders of record at the close of business on November 6, 2013. This distribution equates to an annualized rate of $2.20 per unit, which is unchanged from the distribution paid with respect to the second quarter of 2013 and represents a 1.9% increase over the distribution paid with respect to the third quarter of 2012.

Management Comment

“We are pleased with our third quarter results” said Bill Shea, President and CEO of PVR’s general partner. “The Eastern Midstream Segment continues to show progress in volumes over last year and last quarter and we expect that progress to continue. Our Midcontinent Midstream Segment benefitted from an improved commodity pricing environment, and our Coal and Natural Resource Management Segment has performed in-line with our expectations.”

PVR Reports Third Quarter 2013 Results Page 2

Eastern Midstream Segment Results

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

• Adjusted EBITDA of $43.5 million as compared to $21.4 million last year and $38.1 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 1.4 Bcfd as compared to 0.6 Bcfd last year and 1.3 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 third quarter 2013 results, with comparisons to third quarter 2012 results and the second quarter of 2013, as follows:

• Adjusted EBITDA of $17.1 million as compared to $13.0 million last year and $14.9 million last quarter.

• Quarterly average throughput volumes of 381 MMcfd as compared to 410 MMcfd last year and 382 MMcfd last quarter.

Coal and Natural Resource Management Segment Results

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

• Adjusted EBITDA of $19.3 million as compared to $26.8 million last year and $23.1 million last quarter. The year-over-year decline was primarily due to decreased coal production and pricing.

• Coal royalty tons of 5.7 million tons as compared to 7.7 million tons last year and 6.9 million tons last quarter.

• Coal royalties revenue of $20.8 million, or $3.66 per ton, as compared to $28.8 million, or $3.73 per ton last year and $23.2 million or $3.37 per ton last quarter.

Capital Investment and Resources

We invested $76.9 million on internal growth projects in our midstream businesses during the third quarter of 2013, of which $64.8 million was invested in the Eastern Midstream Segment.

In September PVR closed on a public offering of 5.5 million common units. The terms of the offering granted the underwriter the option to purchase a maximum of 825,000 additional common units. On October 16^th, the underwriter purchased 600,000 units available under that option. Net proceeds from the offering, including the option exercised, totaled approximately $138.1 million and were used to repay a portion of the borrowings outstanding under PVR’s $1.0 billion revolving credit facility. As of September 30, 2013, we had borrowings of $332.5 million under our revolving credit facility.

PVR Reports Third Quarter 2013 Results Page 3

Expansion Projects Update

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

• As previously announced, PVR executed a definitive agreement with Hess Corporation to provide trunkline, gathering and compression services in the Utica Shale.

• Two new compressor facilities in the Eastern Midstream Segment were completed and began operation. These facilities will help maintain volumes of PVR’s Susquehanna/Wyoming gathering system and increase the injection capacity into the Tennessee Gas Pipeline.

• An additional phase of the Lycoming gathering system, for which Inflection Energy is the primary shipper, was completed and began service.

• The PVR/Aqua joint venture water system put a new water truck loading facility into service, which will significantly expand the service territory reach for the water service to natural gas producers.

• The Eastern Midstream Segment connected 25 wells during the third quarter for a total of 68 for the nine months ending September 30^th. PVR currently anticipates connecting an additional 36 wells during the fourth quarter.

• An additional 39 new wells were connected in the Midcontinent Midstream Segment during the third quarter for a total of 144 for the nine months ending September 30^th.

Third Quarter 2013 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss third quarter 2013 financial and operational results, is scheduled for Thursday, October 24, 2013 at 11:00 a.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 athttp://www.videonewswire.com/event.asp?id=96084 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 October 30 by dialing 877-344-7529 (international: 412-317-0088) and using conference playback number 10034216.

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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 atwww.pvrpartners.com.

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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.

PVR Reports Third Quarter 2013 Results Page 4

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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 to complete the proposed merger with Regency Energy Partners L.P., 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						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		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
Interest income and 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
Weighted average number of Class B units outstanding		23,621			21,620			23,129			10,770
Weighted average number of Special units outstanding		10,346			10,346			10,346			5,173
Other data by segment:
Eastern Midstream:
Gathered volumes (MMcfd)		622			444			606			330
Trunkline volumes (MMcfd) (1)		804			169			716			127
Midcontinent Midstream:
Daily throughput volumes (MMcfd)		381			410			385			435
Coal and Natural Resource Management:
Coal royalty tons (in thousands)		5,684			7,703			19,023			23,584

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

PVR PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

	September 30,		December 31,
	2013		2012
Assets
Cash and cash equivalents	$	7,901	$	14,713
Accounts receivable		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, net		2,166,092		1,989,346
Other long-term assets		784,652		844,208
Total assets	$	3,100,280	$	2,998,709
Liabilities and Partners’ Capital
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
Other long-term liabilities		30,976		35,468
Senior notes		1,300,000		900,000
Revolving credit facility		332,500		590,000
Partners’ capital		1,271,002		1,272,419
Total liabilities and partners’ capital	$	3,100,280	$	2,998,709

CONDENSED 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
Commodity derivative contracts:
Total derivative losses (gains) 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	)
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		17,695			23,334			13,472			23,396
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
Repayments (proceeds) from borrowings, net		(125,000	)		103,000			(257,500	)		(6,000	)
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

PVR PARTNERS, L.P.

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

	Three Months Ended September 30,						Nine Months Ended 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
Distribution to Partners:
Total cash distribution paid during the period	$	52,781		$	46,833		$	158,302		$	128,516
Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Net income as adjusted”:
Net income (loss)	$	17,888		$	38,783		$	30,633		$	(63,752	)
Impairments on PP&E and equity investments		—			—			—			124,845
Acquisition related costs		—			—			—			14,049
Gain on sale of assets		(14,302	)		(31,292	)		(14,302	)		(31,292	)
Adjustments for derivatives:
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	)
Net income, as adjusted (c)	$	4,428		$	7,683		$	16,578		$	33,071

(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 or minus derivative losses or gains and minus 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. 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, minus gain on sale of assets. 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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013			2012
Revenues
Gathering fees	$	24,021	$	14,012	$	71,162		$	28,316
Trunkline fees		27,389		11,747		70,143			28,394
Other		309		1,041		(251	)		2,687
Total revenues		51,719		26,800		141,054			59,397
Expenses
Operating		3,190		2,124		8,045			4,211
General and administrative		5,014		3,236		13,713			6,126
Acquisition related costs		—		—		—			14,049
Depreciation, depletion and amortization		25,355		11,867		71,461			22,322
Total expenses		33,559		17,227		93,219			46,708
Operating income	$	18,160	$	9,573	$	47,835		$	12,689

	Midcontinent Midstream
	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		652		1,470		2,313		5,778
Gain on sale of plant		—		31,292		—		31,292
Other		14,637		497		16,183		2,042
Total revenues		211,879		207,522		599,889		571,053
Expenses
Cost of gas purchased		163,824		147,246		489,106		453,543
Operating		11,591		11,164		32,519		31,642
General and administrative		5,059		4,826		16,229		16,575
Impairments		—		—		—		124,845
Depreciation, depletion and amortization		15,719		11,913		45,679		37,220
Total expenses		196,193		175,149		583,533		663,825
Operating income (loss)	$	15,686	$	32,373	$	16,356	$	(92,772	)

	Coal and Natural Resource Management
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Revenues
Coal royalties	$	20,816	$	28,760	$	66,990	$	91,150
Coal services		543		1,953		2,552		4,583
Timber		1,350		1,411		4,468		4,284
Oil and gas royalties		898		977		2,245		2,165
Other		1,759		1,424		8,642		5,544
Total revenues		25,366		34,525		84,897		107,726
Expenses
Operating		2,725		4,299		9,462		11,677
General and administrative		3,329		3,469		10,417		11,873
Depreciation, depletion and amortization		6,059		8,212		20,892		24,759
Total expenses		12,113		15,980		40,771		48,309
Operating income	$	13,253	$	18,545	$	44,126	$	59,417

(1) Includes a $31.3 second quarter gain on sale of plant and a $8.7 million impairment charge related to an equity investment in the fourth quarter of 2012.

PVR PARTNERS, L.P.

DERIVATIVE CONTRACT SUMMARY - unaudited

As of September 30, 2013

	Average Volume Per Day			Swap Price
Crude oil swap (WTI)		(barrels	)		(per barrel	)
Fourth quarter 2013		500		$	94.80
Natural gas swaps(1)		(MMBtu	)		(per MMBtu	)
Fourth quarter 2013		5,500		$	3.823
Propane swap - OPIS Conway		(gallons	)		(per gallon	)
Fourth quarter 2013		42000		$	1.00875

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.

⁽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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
EASTERN MIDSTREAM
Volumes (MMcfd)
Lycoming Trunkline		293		169		323		127
Wyoming Trunkline		511		—		393		—
Total Trunkline Volume		804		169		716		127
Lycoming Gathering		248		203		236		144
Wyoming Gathering		210		149		197		137
East Lycoming Gathering		106		75		115		40
Bradford Gathering		50		13		50		7
Preston Gathering		—		—		—		—
Greene Gathering		8		4		8		2
Total Gathering		622		444		606		330
Total Throughput		1,426		613		1,322		457
Total Trunkline Fees	$	27,389	$	11,747	$	70,143	$	28,394
Total Gathering Fees	$	24,021	$	14,012	$	71,162	$	28,316
Trunkline Fees / Mcf	$	0.37	$	0.76	$	0.36	$	0.82
Gathering Fees / Mcf	$	0.42	$	0.34	$	0.43	$	0.31
MIDCONTINENT MIDSTREAM
Volumes (MMcfd)
Panhandle System		329		360		332		349
Crossroads System (1)		—		—		—		36
Crescent System		29		26		29		24
Hamlin System		6		6		6		7
Total Processing Systems		364		392		367		416
Arkoma System		9		9		9		9
North Texas System		8		9		8		10
Total Gathering Only Systems		17		18		18		19
Total All Systems		381		410		385		435
Total Gathering and Processing Fees, Net (2)	$	33,418	$	28,487	$	94,600	$	84,176
Fees Per Mcf	$	0.95	$	0.75	$	0.90	$	0.71

⁽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		2,609		3,546		8,010		11,090
Northern Appalachia		375		1,013		2,382		2,911
Illinois Basin		424		801		1,753		2,900
San Juan Basin		2,276		2,343		6,878		6,683
Total Tons		5,684		7,703		19,023		23,584
Total Coal Royalties	$	20,816	$	28,760	$	66,990	$	91,150
Average Coal Royalty per ton	$	3.66	$	3.73	$	3.52	$	3.86