Titan Energy 8-K Financial Results for the Third Quarter 2013

Exhibit 99.1

NEWS RELEASE

CONTACT:	Brian J. Begley
	Vice President - Investor Relations
	Atlas Resource Partners, L.P.
	(877) 280-2857
	(215) 405-2718 (fax)

ATLAS RESOURCE PARTNERS, L.P. REPORTS OPERATING AND

FINANCIAL RESULTS FOR THE THIRD QUARTER 2013

• Atlas Resource Partners’ (ARP) average net production for the third quarter 2013 reached a record of 261.4 MMcfed, a 96% increase from the prior quarter, due primarily to newly acquired producing reserves in the Raton and Black Warrior Basins

• Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), including discretionary adjustments by the Board of Directors of the General Partner, was $60.7 million⁽¹⁾ for the third quarter 2013

• Average daily oil production increased by approximately 20% from the prior quarter, mainly from ARP’s continued development in the Marble Falls and Mississippi Lime

• ARP’s newly drilled Marcellus Shale wells continue their tremendous results, currently sustaining production rates at maximum allowable capacity

• ARP’s Raton and Black Warrior Basin assets continue to generate strong benefits for the company from stable, low-cost production

• Development begins on newly identified productive zones for additional oil reserves in the Marble Falls play

• ARP increased its quarterly distribution to $0.56 per limited partner unit for the third quarter 2013, a 4% increase from the second quarter 2013 and a 30% increase from the prior year quarter, on approximately 1.1x distribution coverage for the period

• ARP to discuss third quarter 2013 financial and operational results on a conference call at 9AM ET on Friday, November 8^th

Philadelphia, PA – November 7, 2013 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) has reported operating and financial results for the third quarter 2013.

Matthew A. Jones, President of ARP, said, “Our results this quarter continue the substantial growth our company has experienced over just a short period of time. Having expanded our operations through accretive acquisitions and by the drillbit over the past year and a half, we have significantly grown our proved reserves (+700%) and distributions to unitholders (+40%) over that time. Our drilling activities have been strong, exemplified by the tremendous results from our recently completed Marcellus Shale wells. Now, our enterprise is the strongest it’s been — both in asset diversification and our ability to increase cash flow.”

* * *

• ARP generated adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), including discretionary adjustments by the Board of Directors of the General Partner, of $60.7 million⁽¹⁾ for the third quarter 2013;

• On a GAAP basis, net loss was $39.7 million for the third quarter 2013 compared to a net loss of $10.1 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, including depreciation, depletion and non-cash compensation expense.

• ARP declared a cash distribution of $0.56 per limited partner unit for the third quarter 2013, an approximate 4% increase, over the second quarter 2013 and a 30% increase from the prior year third quarter distribution. The third quarter 2013 ARP distribution will be paid on November 14,

2013 to holders of record as of November 6, 2013. ARP expects to distribute between $0.58 and $0.62 per unit for the fourth quarter 2013, and also expects full year 2014 distributions to be in a range of $2.40 to $2.60 per unit.

⁽¹⁾  Please see footnote 11 to the Financial Information table on page 10 of this release.

E&P Operating Highlights

• Average net daily production for the third quarter 2013 was a record 261.4 million cubic feet of natural gas equivalents per day (“Mmcfed”), an increase of approximately 96% from the second quarter 2013. The increase in net production from the second quarter 2013 was due primarily to the recently acquired producing assets from EP Energy in July 2013, located in the Raton Basin (New Mexico), Black Warrior Basin (Alabama) and County Line region (Wyoming). Production also increased from additional wells connected in the third quarter in several of ARP’s key operating areas, including the Marcellus Shale, Utica Shale, Marble Falls and Mississippi Lime.

• During the third quarter 2013, ARP connected eight horizontal Marcellus Shale wells located in Lycoming County, PA, which demonstrated exceptionally strong initial flow rates. Despite limitations of infrastructure that have inhibited operation at full capacity, total gross daily production from the eight wells reached maximum pipeline capacity of approximately 62 million cubic feet per day (“Mmcfd”). The characteristics of these well sites are highly favorable compared to other wells in the region due to: the thickness and depth of the shale in the area, level of porosity (~10-14%), permeability (up to 400 nD), TOC (up to 6%), and a high pressure gradient (~0.89 psi/ft).

• In September 2013, ARP began connecting its five initial wells drilled in the Utica-Point Pleasant formation in northern Harrison County, OH. Early results indicated higher levels of high-grade condensate than originally expected. Midstream service in the Utica Shale has been disrupted due to the Natrium plant fire which occurred in late September 2013. Nonetheless, ARP has been able to flow limited amount of production from these wells and is in the process of identifying additional third-party capacity in order to optimize production.

• ARP has drilled over 40 wells to date in the oil and liquids rich Marble Falls play, primarily in Jack County, TX in which the Company holds approximately 75,000 net acres. ARP has now identified additional productive zones located above and below the Marble Falls play, including the Caddo formation, Bend conglomerates and Chappel Reefs. Early testing of these formations has yielded initial production rates of 100-300 barrels of oil per day. Additional 3-D seismic is being undertaken to further develop these formations in conjunction with the Marble Falls.

Hedge Positions

• ARP continued to expand its commodity hedge positions on its legacy production during the third quarter 2013. A summary of ARP’s derivative positions as of November 7, 2013 is provided in the financial tables of this release.

Corporate Expenses & Capital Position

• Cash general and administrative expense was $9.6 million for the third quarter 2013, $1.1 million higher than the second quarter 2013 and slightly higher compared with the prior year third quarter. The increase compared with the second quarter 2013 was due primarily to additional personnel associated with the EP Energy acquisition, as well as an increase in other administrative costs due to timing.

• Cash interest expense was $7.9 million for the third quarter 2013, an increase of $4.5 million compared to the second quarter 2013. The increase was primarily due to the recent issuance of $250 million of 9.25% senior notes due 2021, which were used to partially finance the acquisition of natural gas assets from EP Energy in July 2013.

• As of September 30, 2013, ARP had $948 million of total debt, including $425 million outstanding under its revolving credit facility. ARP had approximately $410 million available on its revolving credit facility as of the end of the third quarter.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.’s third quarter 2013 results on Friday, November 8, 2013 at 9:00 am ET by going to theInvestor Relations section of Atlas Resource’s website at www.atlasresourcepartners.com. For those unavailable to listen to the live broadcast, the replay of the webcast will be available following the live call on the Atlas Resource website and telephonically beginning at 11:00 a.m. ET on November 8, 2013 by dialing 888-286-8010, passcode: 71563674.

Atlas Resource Partners, L.P. (NYSE: ARP)is an exploration & production master limited partnership which owns an interest in over 12,000 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Raton Basin (NM) and Black Warrior Basin (AL). ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website atwww.atlasresourcepartners.com, or contact Investor Relations atInvestorRelations@atlasenergy.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 37% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website atwww.atlasenergy.com, or contact Investor Relations atInvestorRelations@atlasenergy.com.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the Mississippi Lime play in Oklahoma and southern Kansas, the Woodford Shale in southeastern Oklahoma, the Permian Basin in western Texas, Eagle Ford Shale in south Texas, as well as gathering pipelines in the Barnett Shale in east Texas and Chattanooga Shale in Tennessee, APL owns and operates 14 active gas processing plants, 18 gas treating facilities, as well as approximately 10,600 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership’s website atwww.atlaspipeline.com or contact IR@atlaspipeline.com.

*    *    *

Cautionary Note Regarding Forward-Looking Statements

This document contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. ARP cautions readers that any forward-looking information is not a guarantee of future performance. Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource and production potential, ARP’s plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, those associated with general economic and business conditions; ARP’s ability to realize the anticipated benefits of its acquisitions; changes in commodity prices and hedge positions; changes in the estimates of maintenance capital expense; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP’s level of indebtedness; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; and other risks, assumptions and uncertainties detailed from time to time in ARP’s reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED 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:
Gas and oil production	$	80,332		$	24,699		$	173,490		$	61,323
Well construction and completion		10,964			36,317			92,293			92,277
Gathering and processing		3,591			4,134			11,639			10,311
Administration and oversight		4,447			4,440			8,923			8,586
Well services		5,023			5,086			14,703			15,344
Other, net		(13,272	)		67			(14,589	)		(4,952	)
Total revenues		91,085			74,743			286,459			182,889
Costs and expenses:
Gas and oil production		29,419			7,295			63,670			16,247
Well construction and completion		9,534			31,581			80,255			79,882
Gathering and processing		4,395			4,558			13,767			13,185
Well services		2,386			2,232			7,009			7,076
General and administrative		31,983			16,147			63,767			48,427
Chevron transaction expense		—			7,670			—			7,670
Depreciation, depletion and amortization		41,656			13,918			85,061			33,848
Total costs and expenses		119,373			83,401			313,529			206,335
Operating loss		(28,288	)		(8,658	)		(27,070	)		(23,446	)
Gain (loss) on asset sales and disposal		(661	)		2			(2,035	)		(7,019	)
Interest expense		(10,748	)		(1,423	)		(22,145	)		(2,529	)
Net loss		(39,697	)		(10,079	)		(51,250	)		(32,994	)
Preferred limited partner dividends		(3,564	)		(1,221	)		(7,592	)		(1,221	)
Net loss attributable to owner’s interest, common limited partners and the general partner	$	(43,261	)	$	(11,300	)	$	(58,842	)	$	(34,215	)
Allocation of net loss:
Portion applicable to owner’s interest (period prior to the transfer of assets on March 5, 2012)	$	—		$	—		$	—		$	250
Portion applicable to common limited partners and general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)		(43,261	)		(11,300	)		(58,842	)		(34,465	)
Net loss attributable to owner’s interest, common limited partners and the general partner	$	(43,261	)	$	(11,300	)	$	(58,842	)	$	(34,215	)
Allocation of net loss attributable to common limited partners and the general partner:
General partner’s interest	$	812		$	(226	)	$	2,135		$	(689	)
Common limited partners’ interest		(44,073	)		(11,074	)		(60,977	)		(33,776	)
Net loss attributable to common limited partners and the general partner	$	(43,261	)	$	(11,300	)	$	(58,242	)	$	(34,465	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.74	)	$	(0.32	)	$	(1.21	)	$	(1.06	)
Weighted average common limited partner units outstanding:
Basic and Diluted		59,440			35,068			50,197			31,865

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

	September 30,		December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	1,452	$	23,188
Accounts receivable		59,669		38,718
Current portion of derivative asset		19,474		12,274
Subscriptions receivable		13,900		55,357
Prepaid expenses and other		11,610		9,063
Total current assets		106,105		138,600
Property, plant and equipment, net		2,175,754		1,302,228
Goodwill and intangible assets, net		32,843		33,104
Long-term derivative asset		28,500		8,898
Long-term derivative receivable from Drilling Partnerships		182		—
Other assets, net		43,468		16,122
	$	2,386,852	$	1,498,952
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	74,686	$	59,549
Advances from affiliates		23,559		5,853
Liabilities associated with drilling contracts		—		67,293
Current portion of derivative liability		318		—
Current portion of derivative payable to Drilling Partnerships		4,932		11,293
Accrued well drilling and completion costs		47,149		47,637
Accrued liabilities		33,873		25,388
Total current liabilities		184,517		217,013
Long-term debt		948,279		351,425
Long-term derivative liability		—		888
Long-term derivative payable to Drilling Partnerships		—		2,429
Asset retirement obligations and other		84,127		65,191
Commitments and contingencies
Partners’ Capital:
General partner’s interest		5,716		7,029
Preferred limited partners’ interests		183,325		96,155
Common limited partners’ interests		929,474		737,253
Class C preferred limited partner warrants		1,176		—
Accumulated other comprehensive income		50,238		21,569
Total partners’ capital		1,169,929		862,006
	$	2,386,852	$	1,498,952

ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Net loss attributable to common limited partners per unit - basic	$	(0.74	)	$	(0.32	)	$	(1.21	)	$	(1.06	)
Cash distributions paid per unit(1)	$	0.56		$	0.43		$	1.61		$	0.95
Production revenues (in thousands):
Natural gas	$	57,350		$	19,945		$	114,789		$	47,789
Oil		12,993			2,239			32,394			7,619
Natural gas liquids		9,989			2,515			26,307			5,915
Total production revenues	$	80,332		$	24,699		$	173,490		$	61,323
Production volume:(2)(3)
Appalachia: (4)
Natural gas (Mcfd)		38,594			38,123			33,651			33,807
Oil (Bpd)		312			259			291			273
Natural gas liquids (Bpd)		12			2			5			14
Total (Mcfed)		40,541			39,687			35,428			35,530
Raton/Black Warrior: (4)(5)
Natural gas (Mcfd)		115,354			—			25,775			—
Oil (Bpd)		—			—			—			—
Natural gas liquids (Bpd)		—			—			—			—
Total (Mcfed)		115,354			—			25,775			—
Barnett/Marble Falls: (6)
Natural gas (Mcfd)		66,145			49,440			66,208			21,278
Oil (Bpd)		899			2			847			1
Natural gas liquids (Bpd)		2,961			865			2,757			230
Total (Mcfed)		89,306			54,642			87,834			22,663
Mississippi Lime/Hunton:(7)
Natural gas (Mcfd)		5,475			5,100			4,739			216
Oil (Bpd)		285			42			144			—
Natural gas liquids (Bpd)		366			340			285			—
Total (Mcfed)		9,382			7,391			7,315			216
Other Operating Areas:(4)
Natural gas (Mcfd)		4,321			5,363			4,571			5,230
Oil (Bpd)		21			16			19			17
Natural gas liquids (Bpd)		395			412			394			408
Total (Mcfed)		6,815			7,932			7,044			7,780
Total Production Per Day:(4)(5)(6)
Natural gas (Mcfd)		191,020			88,208			134,945			60,531
Oil (Bpd)		1,517			277			1,301			291
Natural gas liquids (Bpd)		3,734			1,067			3,441			652
Total (Mcfed)		222,529			96,275			163,397			66,189
Average sales prices: (3)
Natural gas (per Mcf) (8)	$	3.46		$	3.01		$	3.39		$	3.42
Oil (per Bbl)(9)	$	93.07		$	87.86		$	91.19		$	95.70
Natural gas liquids (per Bbl)	$	29.08		$	25.61		$	28.01		$	33.09
Production costs:(3)(10)
Lease operating expenses per Mcfe	$	1.15		$	0.75		$	1.12		$	0.80
Production taxes per Mcfe		0.11			0.13			0.17			0.12
Transportation and compression expenses per Mcfe		0.24			0.25			0.22			0.27
Total production costs per Mcfe	$	1.50		$	1.13		$	1.51		$	1.19
Depletion per Mcfe(3)	$	1.95		$	1.42		$	1.80		$	1.64

⁽¹⁾  Represents the cash distributions declared per limited partner unit for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The cash distribution declared of $0.12 per limited partner unit for the 1^st quarter 2012 reflects a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.

⁽²⁾  Production quantities consist of the sum of (i) ARP’s proportionate share of production from wells in which it has a direct interest, based on ARP’s proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the investment partnerships in which ARP has an interest, based on its equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

⁽³⁾  “Mcf” and “Mcfd” represent thousand cubic feet and thousand cubic feet per day; “Mcfe” and “Mcfed” represent thousand cubic feet equivalents and thousand cubic feet equivalents per day, and “Bbl” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of six Mcf’s to one barrel.

⁽⁴⁾  Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia; Coalbed Methane includes ARP’s production located in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama; Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

⁽⁵⁾  Volumetric production per day for Raton/Black Warrior for the three months ended September 30, 2013 includes production per day for the 61-day period from August 1, 2013, the date we began recognizing production from the assets following the completion of the acquisition, through September 30, 2013. Total Raton/Black Warrior production per day for the nine months ended September 30, 2013 represents volume production for the full 273-day period. Total production per day represents total production volume over the 92 and 273 days within the three and nine months ended September 30, 2013, respectively.

⁽⁶⁾  Volumetric production per day for Barnett for the three months ended September 30, 2012 includes production per day associated with the Titan operational assets for the 68-day period from July 25, 2012, the date of acquisition, through September 30, 2012. Total Barnett production per day for the nine months ended September 30, 2012 represents Barnett volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

⁽⁷⁾  Volumetric production per day for Mississippi Lime for the three months ended September 30, 2012 includes production per day associated with the acquisition of the remaining 50% interest in Equal’s operational assets for the 7-day period from September 24, 2012, the date of acquisition, through September 30, 2012. Total Mississippi Lime production per day for the nine months ended September 30, 2012 represents volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

⁽⁸⁾  ARP’s average sales prices for natural gas before the effects of financial hedging were $3.20 per Mcf and $2.46 per Mcf for the three months ended September 30, 2013 and 2012, respectively, and $3.19 per Mcf and $2.60 per Mcf for the nine months ended September 30, 2013 and 2012, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships. Including the effects of subordination, average natural gas sales prices were $3.26 per Mcf ($3.01 per Mcf before the effects of financial hedging) and $2.46 per Mcf ($1.91 per Mcf before the effects of financial hedging) for the three months ended September 30, 2013 and 2012, respectively, and $3.12 per Mcf ($2.92 per Mcf before the effects of financial hedging) and $2.88 per Mcf ($2.07 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2013 and 2012, respectively.

⁽⁹⁾  ARP’s average sales prices for oil before the effects of financial hedging were $104.03 per barrel and $84.30 per barrel for the three months ended September 30, 2013 and 2012, respectively, and $96.50 per barrel and $93.38 per barrel for the nine months ended September 30, 2013 and 2012, respectively.

⁽¹⁰⁾  Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, production overhead and transportation expenses. These amounts exclude the effects of ARP’s proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within ARP’s investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $1.09 per Mcfe ($1.44 per Mcfe for total production costs) and $0.44 per Mcfe ($0.82 per Mcfe for total production costs) for the three months ended September 30, 2013 and 2012, respectively, and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) and $0.50 per Mcfe ($0.90 per Mcfe for total production costs) for the nine months ended September 30, 2013 and 2012, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)

	September 30, 2013			December 31, 2012
Total debt	$	948,279		$	351,425
Less: Cash		(1,452	)		(23,188	)
Total net debt/(cash)		946,827			328,237
Partners’ capital		1,169,929			862,006
Total capitalization	$	2,116,756		$	1,190,243
Ratio of net debt to capitalization		0.45	x		0.28	x

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Maintenance capital expenditures(1)	$	10,000	$	3,350	$	21,000	$	6,850
Expansion capital expenditures		63,944		24,377		182,996		66,529
Total	$	73,944	$	27,727	$	203,996	$	73,379

⁽¹⁾  Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its DCF and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

ATLAS RESOURCE PARTNERS, L.P.

Financial Information

(unaudited; in thousands, except per unit amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Reconciliation of net loss to non-GAAP measures(1):
Net loss	$	(39,697	)	$	(10,079	)	$	(51,250	)	$	(32,994	)
Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)(2)		—			—			—			(7,880	)
Acquisition and related costs		19,417			2,274			25,897			13,499
Depreciation, depletion and amortization		41,656			13,918			85,061			33,848
Amortization of deferred finance costs		2,847			498			8,642			1,028
Non-cash stock compensation expense		2,959			4,846			10,208			7,861
Maintenance capital expenditures(3)		(9,167	)		(3,050	)		(17,667	)		(6,250	)
Loss (gain) on asset sales and disposal		661			(2	)		2,035			7,019
Chevron transaction expense(4)		—			7,670			—			7,670
Adjustment to reflect cash impact of derivatives(5)		—			656			—			4,518
Premiums paid on swaption derivative contracts associated with asset acquisitions(6)		13,308			25			14,617			5,001
Distributable cash flow attributable to limited partners and the general partner(1)(2)	$	31,984		$	16,756		$	77,543		$	33,320
Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Gas and oil production margin	$	50,913		$	18,060		$	109,820		$	49,594
Well construction and completion margin		1,430			4,736			12,038			12,395
Administration and oversight margin		4,447			4,440			8,923			8,586
Well services margin		2,637			2,854			7,694			8,268
Gathering		(804	)		(424	)		(2,128	)		(2,874	)
Cash general and administrative expenses(7)		(9,607	)		(9,027	)		(27,662	)		(27,067	)
Other, net		36			92			28			49
Adjusted EBITDA(1)		49,052			20,731			108,713			48,951
Cash interest expense(8)		(7,901	)		(925	)		(13,503	)		(1,501	)
Maintenance capital expenditures(3)		(9,167	)		(3,050	)		(17,667	)		(6,250	)
Distributable Cash Flow(1)		31,984			16,756			77,543			41,200
Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)(1)(2)		—			—			—			(7,880	)
Distributable Cash Flow attributable to limited partners and the general partner(1)(2)	$	31,984		$	16,756		$	77,543		$	33,320
Discretionary adjustments considered by the Board of Directors of the General Partner in the determination of quarterly cash distributions:
Net cash from acquisitions from the effective date through closing date(9)		5,244			1,710			25,791			3,210
Well construction and completion margin earned(10)		4,760			—			4,760			—
Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(11)	$	41,988		$	18,466		$	108,094		$	36,530
Distributions Paid(12)	$	39,981		$	17,512		$	101,360		$	33,874
per limited partner unit	$	0.56		$	0.43		$	1.61		$	0.95
Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(13)	$	2,007		$	954		$	6,734		$	2,656

⁽¹⁾  Although not prescribed under generally accepted accounting principles (“GAAP”), ARP’s management believes the presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow (“DCF”) is relevant and useful because it helps ARP’s investors understand its operating performance, allows for easier comparison of it’s results with other master limited partnerships (“MLP”), and is a critical component in the determination of quarterly cash distributions. As a

MLP, ARP is required to distribute 100% of available cash, as defined in its limited partnership agreement (“Available Cash”) and subject to cash reserves established by its general partner, to investors on a quarterly basis. ARP refers to Available Cash prior to the establishment of cash reserves as DCF. EBITDA, Adjusted EBITDA and DCF should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. While ARP’s management believes that its methodology of calculating EBITDA, Adjusted EBITDA and DCF is generally consistent with the common practice of other MLPs, such metrics may not be consistent and, as such, may not be comparable to measures reported by other MLPs, who may use other adjustments related to their specific businesses. EBITDA, Adjusted EBITDA and DCF are supplemental financial measures used by the ARP’s management and by external users of ARP’s financial statements such as investors, lenders under ARP’s credit facility, research analysts, rating agencies and others to assess its:

• Operating performance as compared to other publicly traded partnerships and other companies in the upstream energy sector, without regard to financing methods, historical cost basis or capital structure;

• Ability to generate sufficient cash flows to support its distributions to unitholders;

• Ability to incur and service debt and fund capital expansion;

• The viability of potential acquisitions and other capital expenditure projects; and

• Ability to comply with financial covenants in its Amended Credit Facility, which is calculated based upon Adjusted EBITDA.

DCF is determined by calculating EBITDA, adjusting it for non-cash, non-recurring and other items to achieve Adjusted EBITDA, and then deducting cash interest expense and maintenance capital expenditures. ARP defines EBITDA as net income (loss) plus the following adjustments:

• Interest expense;

• Income tax expense;

• Depreciation, depletion and amortization.

ARP defines Adjusted EBITDA as EBITDA plus the following adjustments:

• Asset impairments;

• Acquisition and related costs;

• Non-cash stock compensation;

• (Gains) losses on asset disposal;

• Cash proceeds received from monetization of derivative transactions;

• Premiums paid on swaption derivative contracts; and

• Other items.

ARP adjusts DCF for non-cash, non-recurring and other items for the sole purpose of evaluating its cash distribution for the quarterly period, with EBITDA and Adjusted EBITDA adjusted in the same manner for consistency. ARP defines DCF as Adjusted EBITDA less the following adjustments:

• Cash interest expense; and

• Maintenance capital expenditures.

⁽²⁾  In accordance with prevailing accounting literature, ARP has adjusted its historical financial statements to present them combined with the historical financial results of the spin-off assets for all periods prior to its spin-off date of March 5, 2012.

⁽³⁾  Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its DCF and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

⁽⁴⁾  Reflects a working capital adjustment recognized in September 2012 related to certain amounts included within the contractual cash transaction adjustment associated with the acquisition of certain natural gas and oil properties, the partnership management business, and other assets from AEI, the former owner of Atlas Energy’s general partner, in February 2011. Under GAAP, purchase accounting for an acquisition can be adjusted for up to twelve months after consummation of the transaction – any adjustments after the twelve month window must be treated as income or expense in an enterprise’s statement of operations. ARP excluded this item from Adjusted EBITDA and DCF for the purpose of evaluating DCF for the period to determine its quarterly cash distribution.

⁽⁵⁾  Includes $4.5 million of net cash proceeds received during the nine months ended September 30, 2012 related to the rebalancing of ARP’s hedge portfolio for production periods during 2015 and 2016. These amounts were not recognized within its statement of operations for the nine months ended September 30, 2012, but will be recognized as income during the 2015 and 2016 production periods the original derivatives were scheduled to be settled. ARP included this item in its determination of Adjusted EBITDA, DCF and cash distributions for the period presented, and will exclude the amount from its determination of such amounts for the 2015 and 2016 periods.

⁽⁶⁾  Swaption derivative contracts grant ARP the option to enter into a swap derivative transaction to hedge future production period sales prices for a stated option period, which generally have a duration of a few months and commences upon entering into the derivative contract, in return for an upfront premium. The amounts included within the reconciliation reflect the amortization of premiums ARP paid to enter into swaption derivative contracts for certain acquired volumes over the option period. Generally, ARP enters into swaption derivative contracts to hedge acquired volumes after the announcement of the signed definitive purchase and sale agreement to acquire the oil and gas properties, but before it closes on the transaction, as its senior secured revolving credit agreement does not allow it to hedge production volume until it owns such volumes. ARP excludes such costs in its determination of DCF, Adjusted EBITDA and cash distributions for the respective period as they are specific to the related transaction.

⁽⁷⁾  Excludes non-cash stock compensation expense and certain acquisition and related costs.

⁽⁸⁾  Excludes non-cash amortization of deferred financing costs.

⁽⁹⁾  These amounts reflect net cash proceeds received from the respective effective date through the respective closing date of assets acquired, less estimated and pro forma amounts of maintenance capital expenditures and financing costs. The management of ARP believes these amounts are critical in its evaluation of DCF and cash distributions for the period. Under GAAP, such amounts are characterized as purchase price adjustments and are reflected in the net purchase price paid for the acquired assets, rather than reflected as components of net income or loss for the period. For the 3^rd quarter 2013, such amounts include net cash generated by the EP Energy assets of $6.9 million for period from July 1, 2013 to July 31, 2013, less pro forma interest expense of $0.8 million and estimated maintenance capital expenditures of $0.8 million. For the 3^rd quarter 2012, such amounts include net cash generated by the Titan assets from July 1, 2012 to July 24, 2012 and the Equal assets from July 1, 2012 to September 23, 2012 of $2.0 million, less estimated maintenance capital expenditures of $0.3 million. For the nine months ended September 30, 2013, such amounts include pro forma net cash generated by the EP Energy assets of $32.4 million from April 1, 2013 to July 31, 2013, less pro forma interest expense of $3.3 million and estimated maintenance capital expenditures of $3.3 million. For the nine months ended September 30, 2012, such amounts include net cash generated by the Titan assets from July 1, 2012 to July 24, 2012, the Equal assets from July 1, 2012 to September 23, 2012, and the Carrizo assets from April 1, 2012 to April 29, 2012 of $3.8 million, less estimated maintenance capital expenditures of $0.6 million.

⁽¹⁰⁾  This amount reflects well construction and completion margin from the deployment of capital for the investment partnership programs during the 3^rd quarter 2013 for which ARP was required to defer recognition under GAAP until additional investor funds were received. Under ARP’s annual investment partnership programs, investor funds must be received by the particular investment partnership by December 31^st of that calendar year to be eligible for an investment in that program.

⁽¹¹⁾  Including the discretionary adjustments by the Board of Directors of the General Partner in the determination of quarterly cash distributions, Adjusted EBITDA would have been $60.7 million and $22.7 million for the three months ended September 30, 2013 and 2012, respectively, and $145.9 million and $52.8 million for the nine months ended September 30, 2013 and 2012, respectively.

⁽¹²⁾  Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The cash distribution declared of $0.12 per limited partner unit for the 1st quarter 2012 reflected a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.

⁽¹³⁾  ARP seeks to at least maintain its current cash distribution in future quarterly periods, and expects to only increase such cash distributions when future Distributable Cash Flow amounts allow for it and are expected to be sustained. The Partnership’s determination of quarterly cash distributions and its resulting determination of the amount of excess (shortfall) those cash distributions generate in comparison to Distributable Cash Flow are based upon its assessment of numerous factors, including but not limited to future commodity price and interest rate movements, variability of well productivity, weather effects, and financial leverage. ARP also considers its historical trailing four quarters of excess or shortfalls and future forecasted excess or shortfalls that its cash distributions generate in comparison to Distributable Cash Flow due to the variability of its Distributable Cash Flow generated each quarter, which could cause it to have more or less excess (shortfalls) generated from quarter to quarter.

ATLAS RESOURCE PARTNERS, L.P.

Hedge Position Summary

(as of November 7, 2013)

Natural Gas

Fixed Price Swaps
Production Period Ended December 31,	Average Fixed Price (per mmbtu)(a)		Volumes (mmbtus)(a)
2013(b)	$	3.91		15,597,417
2014	$	4.15		60,152,976
2015	$	4.24		50,274,492
2016	$	4.32		43,946,320
2017	$	4.53		24,840,000
2018	$	4.72		3,960,000

Costless Collars
Production Period Ended December 31,	Average Floor Price per mmbtu)(a)		Average Ceiling Price per mmbtu)(a)		Volumes (mmbtus)(a)
2013(b)	$	4.40	$	5.44		1,380,000
2014	$	4.22	$	5.12		3,840,000
2015	$	4.23	$	5.13		3,480,000

Natural Gas Liquids

Crude Oil Fixed Price Swaps
Production Period Ended December 31,	Average Fixed Price (per bbl)(a)		Volumes (bbls)(a)
2013(b)	$	93.66		27,000
2014	$	91.57		105,000
2015	$	88.55		96,000
2016	$	85.65		84,000
2017	$	83.78		60,000

Mt Belvieu Ethane Purity Swaps
Production Period Ended December 31,	Average Fixed Price (per gallon)		Volumes (bbls)(a)
2014	$	0.3025		60,000

Mt Belvieu Propane Swaps
Production Period Ended December 31,	Average Fixed Price (per gallon)		Volumes (bbls)(a)
2013(b)	$	1.0835		69,000
2014	$	0.9996		294,000
2015	$	1.0125		132,000

Mt Belvieu Butane Swaps
Production Period Ended December 31,	Average Fixed Price (per gallon)		Volumes (bbls)(a)
2014	$	1.2750		18,000
2015	$	1.2150		18,000
Mt Belvieu Iso-Butane Swaps
Production Period Ended December 31,	Average Fixed Price (per gallon)		Volumes (bbls)(a)
2014	$	1.2900		18,000
2015	$	1.2275		18,000

Crude Oil

Fixed Price Swaps
Production Period Ended December 31,	Average Fixed Price (per bbl)(a)		Volumes (bbls)(a)
2013(b)	$	93.74		127,650
2014	$	92.67		552,000
2015	$	88.14		567,000
2016	$	85.52		225,000
2017	$	83.30		132,000

Costless Collars
Production Period Ended December 31,	Average Floor Price (per bbl)(a)		Average Ceiling Price (per bbl)(a)		Volumes (bbls)(a)
2013(b)	$	90.00	$	116.40		15,000
2014	$	84.17	$	113.31		41,160
2015	$	83.85	$	110.65		29,250

^(a)  “mmbtu” represents million metric British thermal units.; “bbl” represents barrel.

^(b)  Reflects hedges covering the last three months of 2013.