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 FOURTH QUARTER AND FULL YEAR 2014

 

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Adjusted EBITDA, including discretionary adjustments by the Board of Directors of the General Partner, was $87.1 million(1) for the fourth quarter 2014, an approximate 39% increase from the prior year quarter

 

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Distributable cash flow, including discretionary adjustments by the Board of Directors of the General Partner, was $47.1 million(1) for the fourth quarter 2014, an approximate 29% increase from the prior year quarter

 

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ARP updated its 2015 financial outlook, including full year distribution guidance of $1.30 per unit at an expected coverage range of 1.2x to 1.4x

 

•

ARP will discuss fourth quarter and full year 2014 financial and operational results on a conference call at 9AM ET on Monday, March 2nd

Philadelphia, PA – March 2, 2015 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) has reported operating and financial results for the fourth quarter and full year 2014.

Matthew A. Jones, President of ARP, stated, “Our business experienced yet another year of substantial growth and development. We believe that our diversified oil & gas asset base, cash flow from both our production and partnership management business, and the financial actions we have recently taken will allow us to add stability in the current environment.”

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Fourth quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $87.1 million(1), compared to $107.4 million for the third quarter 2014, and $62.6 million for the prior year comparable quarter. Full year 2014 Adjusted EBITDA, including discretionary adjustments by the Board of Directors of the General Partner, was $338.2 million, which was 62% higher than full year 2013 Adjusted EBITDA of $208.6 million. The decrease from the sequential quarter was primarily due to lower realized production margin from the Company’s Eagle Ford and Rangely production, which experienced lower volumes during the period. The variance in production volumes in these areas was attributable to scheduled maintenance activity in the Rangeley Field, and temporary well shut-ins from offset well completions in the Eagle Ford, as well as expected decline from flush Eagle Ford production in prior periods. Results were also affected by lower partnership margin and higher cash general and administrative costs. The increase in Adjusted EBITDA compared to the prior year quarter and full year 2013 was due to cash flow contribution from recently acquired assets in the Eagle Ford shale in south Texas, the acquisition of the Rangely Field oil and liquids assets in northwest Colorado in June 2014, and the acquisition of the GeoMet natural gas assets in West Virginia in May 2014.

 

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Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $47.1 million(1), or approximately $0.51 per common unit, for the fourth quarter 2014, compared to $62.7 million for the third quarter 2014 and $36.6 million for the prior year comparable quarter. Full

 

(1)	A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 8 to the Financial Information table of this release.

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year 2014 Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner was $197.7 million, a 45% increase from the full year 2013 Distributable Cash Flow of $136.4 million. Please see above for explanations of the variances in Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner.

 

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ARP paid monthly cash distributions totaling approximately $0.59 per limited partner unit for the fourth quarter 2014. On February 23, 2015, ARP announced the January 2015 monthly distribution of $0.1083 per unit ($1.30 per unit on an annualized basis), which will be paid on March 17, 2015 to unitholders of record as of March 10, 2015. ARP expects to achieve a distribution coverage ratio of 1.2x to 1.4x for the full year 2015 at the current distribution level, assuming current forward strip prices for oil and natural gas.

 

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The Company’s partnership management business raised $166.8 million from its Series 34 – 2014 private placement fundraising in 2014. This amount is over 11% higher than the fundraising amount for its 2013 program, and the Series 34 capital is expected to be deployed to drill new wells in the Eagle Ford Shale, Utica Shale, Mississippi Lime and Marble Falls.

 

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On a GAAP basis, net loss was $580.8 million for the fourth quarter 2014 compared with net income of $1.1 million for the third quarter 2014 and a net loss of $40.0 million for the prior year comparable period. The net loss for the fourth quarter 2014 was principally generated by non-cash expenses, specifically depreciation and amortization and an asset impairment charge on certain oil and gas properties due recent declines in forward commodity prices. Full year 2014 net loss was $611.0 million, as compared to a net loss of $91.2 million for the full year 2013. The full year net loss increased for similar reasons as mentioned above.

2015 Financial Outlook

ARP has provided an updated financial outlook for the full year 2015, which includes expected cash distributions of $1.30 per unit with distribution coverage of approximately 1.2x to 1.4x. The following are several of the key assumptions included in the forecast:

 

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Net production volume per day of approximately 289.5 million cubic feet equivalents per day (“Mmcfed”)

 

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Net realized natural gas price after hedges of $3.58/mcf (72% hedged)

 

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Net realized crude oil price after hedges of $73.76/bbl (68% hedged)

 

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Total net production costs of approximately $1.90 per thousand cubic feet equivalent

 

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$150.0 million in partnership management funds raised for the year ending December 31, 2015

 

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Total capital expenditures of approximately $172 million for the year ending December 31, 2015, including approximately $62 million of maintenance capital expenditures

 

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ARP’s forecast for full year 2015 does not assume any consummated acquisitions or net proceeds from the issuance of additional limited partner units.

Recent Events

Merger Transaction Between Targa Resources, Atlas Energy and Atlas Pipeline

On February 27, 2015, ARP’s parent company, Atlas Energy, L.P. (NYSE: ATLS), and ATLS’ midstream subsidiary, Atlas Pipeline Partners, L.P. (NYSE: APL), completed their previously announced merger transactions of Atlas Energy with a subsidiary of Targa Resources Corp. (NYSE: TRGP) (“TRC”) (“ATLS Merger”) and Atlas Pipeline with a subsidiary of Targa Resources Partners LP (“TRP”) (“APL Merger”). The consummation of the mergers followed the approval of the mergers by ATLS and APL unitholders as well as TRC stockholders at special meetings which occurred on Friday, February 20, 2015.

Immediately prior to the closing of the acquisition of ATLS by TRC, ATLS transferred its non-midstream assets to Atlas Energy Group, LLC (“AEG”), a wholly owned subsidiary of ATLS, and then distributed to the ATLS unitholders common units representing a 100% limited liability company interest in AEG. Among other interests, AEG now owns 100% of the general partner interest and a 28% limited partner interest in ARP.

 

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Year End 2014 Oil & Gas Reserves

During the 2014 calendar year, ARP continued to increase its oil & gas reserves and undeveloped properties through both strategic acquisitions as well as organic development. This activity was highlighted by ARP’s acquisitions of natural gas properties in West Virginia (GeoMet), mature oil properties in the Rangely Field in northwest Colorado, and oil-rich reserves in the Eagle Ford shale in south Texas. These acquisitions were accompanied by ongoing development in the Company’s key operating areas of the Mississippi Lime, Marble Falls and the Utica Shale.

As of December 31, 2014, based on the SEC average price assumptions of $4.35 per mcf for natural gas and $94.99 per barrel for crude oil, net proved oil and gas reserves were approximately 1.429 trillion cubic feet equivalents (“Tcfe”), an increase of approximately 22% from the year end 2013 reserve levels. The year end 2014 reserves were valued at a PV-10 amount of approximately $1.99 billion, which does not include the value of ARP’s commodity derivatives. The fair value of ARP’s commodity derivatives at December 31, 2014 was approximately $266.5 million. Approximately 77% of ARP’s reserves were proved developed, compared to 68% at the end of 2013.

E&P Operating Results

 

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Average net daily production for the fourth quarter 2014 was 285.1 Mmcfed, approximately 10% higher than the prior year comparable quarter. The increase in net production from the prior year quarter was due primarily to the acquisition of the Eagle Ford assets in November 2014, as well as the Rangely Field assets in June 2014 and the GeoMet natural gas production assets in May 2014.

 

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ARP’s net realized price for natural gas including the effect of hedge positions was $3.66 per mcf for the fourth quarter, compared to $3.55 per mcf for the third quarter 2014. Net realized oil prices including the effect of hedge positions averaged $84.81 per barrel for the fourth quarter 2014, compared to $90.18 for the third quarter 2014.

 

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Investment partnership margin contributed $13.6 million to Adjusted EBITDA and distributable cash flow for the fourth quarter 2014 compared with $18.1 million for the sequential quarter. The $4.5 million decrease in investment partnership margin was due to higher amounts of capital deployed during the 3rd quarter due to scheduled changes in well drilling activity.

Hedge Positions

 

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ARP continued to expand its commodity hedge positions on its existing production during the fourth quarter and full year 2014. A summary of ARP’s derivative positions as of March 2, 2015 is provided in the financial tables of this release. During the fourth quarter 2014, ARP was approximately 75% hedged on its net natural gas production and approximately 90% hedged on its net oil production.

Corporate Expenses & Capital Position

 

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Cash general and administrative expense was $13.1 million for the fourth quarter 2014, $3.6 million higher than the third quarter 2014 and $5.3 million higher than the prior year fourth quarter. The increase compared with prior periods was due primarily to higher costs related to increased personnel managing ARP’s expanded asset base, as well as higher administrative and marketing costs associated with ARP’s 2014 partnership program.

 

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Cash interest expense was $16.0 million for the fourth quarter 2014, $1.8 million higher than the third quarter 2014 and $4.8 million higher than the prior year fourth quarter. The increase from the third quarter 2014 prior periods was primarily due to higher levels of borrowing used to expand ARP’s operations over the prior periods, including the issuance of an additional $75 million of the Company’s 9.25% Senior Notes due in 2021, from which the proceeds were utilized to purchase the Eagle Ford Shale assets during the fourth quarter 2014. The increase compared to the prior year quarter was due to the issuance of the 9.25% Senior Notes above, as well as a $100 million follow-on offering in May 2014 of the Company’s 7.75% Senior Notes due in 2021 to partially fund ARP’s acquisition of oil producing properties in the Rangely Field in northwest Colorado.

 

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At December 31, 2014, ARP had $1.394 billion of total debt, including $696.0 million outstanding under its revolving credit facility. The increase in total debt from the third quarter 2014 was due primarily to the issuance of the additional 9.25% Senior Notes during the fourth quarter 2014 to partially fund the Eagle Ford acquisition on November 5, 2014.

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ARP will be discussing its fourth quarter and full year 2014 results on an investor call with management on Monday, March 2, 2015 at 9:00 am Eastern Time. Interested parties are invited to access the live webcast the investor call by going to the Investor 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 approximately 1:00 p.m. ET on March 2, 2015 by dialing 855-859-2056, passcode: 89716873.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 14,500 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM), Black Warrior Basin (AL) and the Rangely Field in Colorado. ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Energy Group, LLC (NYSE: ATLS) is a master limited partnership which owns the following interests: all of the general partner interest, incentive distribution rights and an approximate 28% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P.; the general partner interests, incentive distribution rights and limited partner interests in its private E&P development subsidiary; and a general partner interest in Lightfoot Capital Partners, an entity that invests directly in energy-related businesses and assets. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

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Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed within this press release are forward-looking statements. Although Atlas Resource Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Resource Partners does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. 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 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 benefits of its acquisitions; changes in commodity prices; 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, current reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and we assume no obligation to update such statements, except as may be required by applicable law.

 

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ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except per unit data)

 

		Three Months Ended								Years Ended
		December 31,								December 31,
		2014				2013				2014				2013
Revenues:
Gas and oil production		$	128,261			$	93,293			$	453,957			$	266,783
Well construction and completion			46,647				75,590				173,564				167,883
Gathering and processing			2,820				4,037				14,107				15,676
Administration and oversight			3,492				3,354				15,564				12,277
Well services			6,518				4,789				24,959				19,492
Other, net			3,066				133				3,409				(14,456	)
Total revenues			190,804				181,196				685,560				467,655
Costs and expenses:
Gas and oil production			47,717				33,567				176,194				97,237
Well construction and completion			40,562				65,730				150,925				145,985
Gathering and processing			3,625				4,245				15,525				18,012
Well services			2,482				2,506				10,007				9,515
General and administrative			21,455				14,296				72,349				78,063
Depreciation, depletion and amortization			62,641				51,702				233,731				136,763
Asset impairment			573,774				38,014				573,774				38,014
Total costs and expenses			752,256				210,060				1,232,505				523,589
Operating loss			(561,452	)			(28,864	)			(546,945	)			(55,934	)
Gain (loss) on asset sales and disposal			(183	)			1,048				(1,869	)			(987	)
Interest expense			(19,116	)			(12,179	)			(62,144	)			(34,324	)
Net loss			(580,751	)			(39,995	)			(610,958	)			(91,245	)
Preferred limited partner dividends			(5,969	)			(4,400	)			(19,267	)			(11,992	)
Net loss attributable to common limited partners and the general partner		$	(586,720	)		$	(44,395	)		$	(630,225	)		$	(103,237	)
Allocation of net loss attributable to common limited partners and the general partner:
General partner’s interest		$	(8,673	)		$	1,209			$	(1,299	)		$	3,344
Common limited partners’ interest			(578,047	)			(45,604	)			(628,926	)			(106,581	)
Net loss attributable to common limited partners and the general partner		$	(586,720	)		$	(44,395	)		$	(630,225	)		$	(103,237	)
Net loss attributable to common limited partners per unit:
Basic and Diluted		$	(7.06	)		$	(0.77	)		$	(8.42	)		$	(2.03	)
Weighted average common limited partner units outstanding:
Basic and Diluted			81,919				59,447				74,716				52,528

 

 

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ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

 

		December 31,
		2014				2013
ASSETS
Current assets:
Cash and cash equivalents		$	15,247			$	1,828
Accounts receivable			112,038				58,822
Current portion of derivative asset			141,366				1,891
Subscriptions receivable			32,398				47,692
Prepaid expenses and other			26,011				10,097
Total current assets			327,060				120,330
Property, plant and equipment, net			2,208,171				2,120,818
Goodwill and intangible assets, net			14,330				32,747
Long-term derivative asset			127,933				27,084
Other assets, net			50,081				42,821
		$	2,727,575			$	2,343,800
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	109,049			$	69,346
Advances from affiliates			4,271				26,742
Liabilities associated with drilling contracts			40,611				49,377
Current portion of derivative liability			—				6,353
Accrued well drilling and completion costs			80,404				40,481
Distribution payable			20,876				—
Accrued liabilities			83,847				51,416
Total current liabilities			339,058				243,715
Long-term debt			1,394,460				942,334
Asset retirement obligations and other			108,561				90,460
Commitments and contingencies
Partners’ Capital:
General partner’s interest			(13,697	)			4,482
Preferred limited partners’ interests			163,522				183,477
Common limited partners’ interests			548,586				852,457
Class C common limited partner warrants			1,176				1,176
Accumulated other comprehensive income			185,909				25,699
Total partners’ capital			885,496				1,067,291
		$	2,727,575			$	2,343,800

 

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ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)

 

		Three Months Ended								Years Ended
		December 31,								December 31,
		2014				2013				2014				2013
Net loss attributable to common limited partners per unit - basic		$	(7.06	)		$	(0.77	)		$	(8.42	)		$	(2.03	)
Cash distributions paid per unit(1)		$	0.590			$	0.580			$	2.343			$	2.190
Production revenues (in thousands):
Natural gas		$	75,790			$	71,440			$	302,826			$	186,229
Oil			42,444				11,766				110,070				44,160
Natural gas liquids			10,027				10,087				41,061				36,394
Total production revenues		$	128,261			$	93,293			$	453,957			$	266,783
Production volume:(2)(3)
Appalachia: (4)
Natural gas (Mcfd)			35,420				45,768				38,160				36,705
Oil (Bpd)			355				452				381				332
Natural gas liquids (Bpd)			43				70				41				22
Total (Mcfed)			37,807				48,904				40,689				38,825
Coal-bed Methane: (4)
Natural gas (Mcfd)			126,511				113,346				120,768				47,848
Oil (Bpd)			—				—				—				—
Natural gas liquids (Bpd)			—				—				—				—
Total (Mcfed)			126,511				113,346				120,768				47,848
Barnett/Marble Falls:
Natural gas (Mcfd)			54,143				61,625				57,361				65,053
Oil (Bpd)			923				692				1,066				808
Natural gas liquids (Bpd)			2,598				2,734				2,698				2,751
Total (Mcfed)			75,264				82,179				79,946				86,409
Rangely/Eagle Ford: (4) (5)
Natural gas (Mcfd)			693				—				175				—
Oil (Bpd)			3,535				—				1,538				—
Natural gas liquids (Bpd)			421				—				173				—
Total (Mcfed)			24,433				—				10,438				—
Mississippi Lime/Hunton:
Natural gas (Mcfd)			8,339				5,269				6,810				4,873
Oil (Bpd)			599				252				427				171
Natural gas liquids (Bpd)			669				432				561				322
Total (Mcfed)			15,948				9,374				12,734				7,834
Other Operating Areas: (4)
Natural gas (Mcfd)			3,152				3,922				3,253				4,408
Oil (Bpd)			27				16				25				18
Natural gas liquids (Bpd)			310				333				330				378
Total (Mcfed)			5,177				6,018				5,384				6,786
Total Production: (3)(5)
Natural gas (Mcfd)			228,258				229,931				226,526				158,886
Oil (Bpd)			5,440				1,413				3,436				1,329
Natural gas liquids (Bpd)			4,040				3,569				3,802				3,473
Total (Mcfed)			285,139				259,821				269,958				187,701
Average sales prices: (3)
Natural gas (per Mcf) (6)		$	3.66			$	3.63			$	3.76			$	3.47
Oil (per Bbl)(7)		$	84.81			$	90.51			$	87.76			$	91.01
Natural gas liquids (per Bbl) (8)		$	26.97			$	30.72			$	29.59			$	28.71
Production costs:(3)(9)
Lease operating expenses per Mcfe		$	1.34			$	1.03			$	1.29			$	1.09
Production taxes per Mcfe			0.28				0.18				0.27				0.18
Transportation and compression expenses per Mcfe			0.22				0.28				0.25				0.24
Total production costs per Mcfe		$	1.84			$	1.49			$	1.81			$	1.50
Depletion per Mcfe(3)		$	2.28			$	2.07			$	2.27			$	1.89

 

 

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(1)	Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each month within each quarter, based upon the distributable cash flow generated during the respective period.

(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 (excluding the Cedar Bluff area); Coal-bed methane includes ARP’s production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Cedar Bluff area of West Virginia and Virginia, and the County Line area of Wyoming; Rangely/Eagle Ford includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and its production located in southern Texas; Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

(5)

Volumetric production per day for Rangely/Eagle Ford for the year ended December 31, 2014 includes Rangely production from July 1, 2014, the date of the acquisition, through December 31, 2014; Eagle Ford includes production from November 5, 2014, the date of the acquisition, through December 31, 2014. Production per day for Rangely/Eagle Ford and total production per day represents total production volume over the 92 and 365 days within the three months and year ended December 31, 2014, respectively.

(6)

ARP’s average sales prices for natural gas before the effects of financial hedging were $3.51 per Mcf and $3.35 per Mcf for the three months ended December 31, 2014 and 2013, respectively, and $3.93 per Mcf and $3.25 per Mcf for the year ended December 31, 2014 and 2013, 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 $3.61 per Mcf ($3.46 per Mcf before the effects of financial hedging) and $3.38 per Mcf ($3.10 per Mcf before the effects of financial hedging) for the three months ended December 31, 2014 and 2013, respectively, and $3.66 per Mcf ($3.84 per Mcf before the effects of financial hedging) and $3.21 per Mcf ($2.99 per Mcf before the effects of financial hedging) for the years ended December 31, 2014 and 2013, respectively.

(7)	ARP’s average sales prices for oil before the effects of financial hedging were $65.29 per barrel and $94.17 per barrel for the three months ended December 31, 2014 and 2013, respectively, and $82.22 per barrel and $95.88 per barrel for the years ended December 31, 2014 and 2013, respectively.

(8)

ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $21.80 per barrel and $32.04 per barrel for the three months ended December 31, 2014 and 2013, respectively, and $29.39 per barrel and $29.43 per barrel for the years ended December 31, 2014 and 2013, respectively.

(9)

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 $1.32 per Mcfe ($1.82 per Mcfe for total production costs) and $0.94 per Mcfe ($1.40 per Mcfe for total production costs) for the three months ended December 31, 2014 and 2013, respectively, and $1.27 per Mcfe ($1.79 per Mcfe for total production costs) and $1.01 per Mcfe ($1.42 per Mcfe for total production costs) for the years ended December 31, 2014 and 2013, respectively.

 

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ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)

 

		December 31, 2014				December 31, 2013
Total debt		$	1,394,460			$	942,334
Less: Cash			(15,247	)			(1,828	)
Total net debt/(cash)			1,379,213				940,506
Partners’ capital			885,496				1,067,291
Total capitalization		$	2,264,709			$	2,007,797
Ratio of net debt to capitalization			0.61x				0.47x

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

 

		Three Months Ended December 31,								Years Ended December 31,
		2014				2013				2014				2013
Maintenance capital expenditures (1)		$	19,000			$	10,500			$	65,300			$	31,500
Expansion capital expenditures			43,149				49,041				147,334				232,037
Total		$	62,149			$	59,541			$	212,634			$	263,537

 

(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 Distributable Cash Flow 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.

 

9

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ATLAS RESOURCE PARTNERS, L.P.

Financial Information

(unaudited; in thousands, except per unit amounts)

 

		Three Months Ended								Years Ended
		December 31,								December 31,
		2014				2013				2014				2013
Reconciliation of net loss to non-GAAP measures(1):
Net loss		$	(580,751	)		$	(39,995	)		$	(610,958	)		$	(91,245	)
Acquisition and related costs			5,049				4,026				17,814				29,923
Depreciation, depletion and amortization			62,641				51,702				233,731				136,763
Asset impairment			573,774				38,014				573,774				38,014
Amortization of deferred finance costs			3,155				1,007				9,445				9,649
Non-cash stock compensation expense			1,725				2,471				8,067				12,679
Maintenance capital expenditures(2)			(16,300	)			(10,500	)			(50,550	)			(28,167	)
Preferred unit distribution			(4,707	)			(4,400	)			(18,005	)			(12,677	)
Loss (gain) on asset sales and disposal			183				(1,048	)			1,869				987
Premiums paid on swaption derivative contracts associated with asset acquisitions(3)			—				—				—				14,617
Non-cash valuation allowance			1,590				—				1,590				—
Unrealized gain on mark-to-market derivatives			(2,819	)			—				(2,819	)			—
Other			(188	)			53				(204	)			53
Distributable cash flow attributable to limited partners and the general partner(1)		$	43,352			$	41,330			$	163,754			$	110,596
Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Gas and oil production margin		$	80,544			$	59,726			$	277,763			$	169,546
Well construction and completion margin			6,085				9,860				22,639				21,898
Administration and oversight margin			3,492				3,354				15,564				12,277
Well services margin			4,036				2,283				14,952				9,977
Gathering and processing margin			(805	)			(208	)			(1,418	)			(2,336	)
Cash general and administrative expenses(4)			(13,091	)			(7,799	)			(44,878	)			(35,461	)
Other, net			59				186				386				214
Adjusted EBITDA(1)			80,320				67,402				285,008				176,115
Cash interest expense(5)			(15,961	)			(11,172	)			(52,699	)			(24,675	)
Preferred unit distribution			(4,707	)			(4,400	)			(18,005	)			(12,677	)
Maintenance capital expenditures(2)			(16,300	)			(10,500	)			(50,550	)			(28,167	)
Distributable Cash Flow attributable to limited partners and the general partner(1)		$	43,352			$	41,330			$	163,754			$	110,596
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(6)			3,757				—				33,959				25,791
Well construction and completion margin earned(7)			—				(4,760	)			—				—
Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(8)		$	47,109			$	36,570			$	197,713			$	136,387
Distributions Paid(9)		$	53,729			$	37,381			$	198,740			$	130,464
per limited partner unit		$	0.590			$	0.580			$	2.343			$	2.190
Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(10)		$	(6,620	)		$	(811	)		$	(1,027	)		$	5,923

 

(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 its 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

 

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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; and

 

•

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;

 

•

Non-cash valuation allowances; 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;

 

•

Preferred unit cash distributions; and

 

•

Maintenance capital expenditures.

 

(2)

Production from oil and gas assets naturally declines in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such declines 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.

(3)

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.

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

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

(6)

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 three months ended December 31, 2014, such amounts include net cash generated by the Eagle Ford assets from October 1, 2014 to November 4, 2014 of $6.8 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.7 million. For the year ended December 31, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to May 11, 2014, the Rangely assets from April 1, 2014 to June 30, 2014, and the Eagle Ford assets from July 1, 2014 to November 4, 2014 of $53.2 million, less pro forma interest expense of $2.8 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $14.7 million. For the year ended December 31, 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to July 31, 2013 of $32.4 million, less pro forma interest expense of $3.3 million and estimated maintenance capital expenditures of $3.3 million.

(7)

This amount reflects well construction and completion margin from the deployment of capital for the investment partnership programs during the three months ended September 30, 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 31st of that calendar year to be eligible for an investment in that program.

(8)

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 $87.1 million and $62.6 million for the three months ended December 31, 2014 and 2013, respectively, and $338.2 million and $208.6 million for the years ended December 31, 2014 and 2013, respectively.

 

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(9)	Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each month within each quarter, based upon the distributable cash flow generated during the respective period.

(10)

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. ARP’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.

 

12

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ATLAS RESOURCE PARTNERS, L.P.

Hedge Position Summary

(as of March 2, 2015)

Natural Gas

Fixed Price Swaps

 

Production Period Ended December 31,		Average Fixed Price (per mmbtu)(a)				Volumes (mmbtus)(a)
2015		$	4.23				54,834,492
2016		$	4.23				53,546,320
2017		$	4.22				49,920,000
2018		$	4.17				40,800,000
2019		$	4.02				15,960,000

Costless Collars

 

Production Period Ended December 31,		Average Floor Price (per mmbtu)(a)				Average Ceiling Price (per mmbtu)(a)				Volumes (mmbtus)(a)
2015		$	4.23			$	5.13				3,480,000

Put Options – Drilling Partnerships

 

Production Period Ended December 31,		Average Fixed Price (per mmbtu)(a)				Average Volumes (mmbtus)(a)
2015		$	4.00				1,440,000
2016		$	4.15				1,440,000

WAHA Basis Swaps

 

Production Period Ended December 31,		Average Fixed Price (per mmbtu)(a)				Average Volumes (mmbtus)(a)
2015		$	(0.0821	)			5,250,000

Crude Oil

Fixed Price Swaps

 

Production Period Ended December 31,		Average Fixed Price (per bbl)(a)				Volumes (bbls)(a)
2015		$	88.31				1,878,000
2016		$	83.50				1,425,000
2017		$	77.28				1,140,000
2018		$	76.28				1,080,000
2019		$	68.37				540,000

Costless Collars

 

Production Period Ended December 31,		Average Floor Price (per bbl)(a)				Average Ceiling Price (per bbl)(a)				Volumes (bbls)(a)
2015		$	83.85			$	110.65				29,250

 

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

 

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Natural Gas Liquids

Crude Oil Fixed Price Swaps

 

Production Period Ended December 31,		Average Fixed Price (per bbl)(a)				Volumes (bbls)(a)
2016		$	85.65				84,000
2017		$	83.78				60,000

Mt Belvieu Propane Swaps

 

Production Period Ended December 31,		Average Fixed Price (per gallon)				Volumes (bbls)(a)
2015		$	1.0161				192,000

Mt Belvieu Butane Swaps

 

Production Period Ended December 31,		Average Fixed Price (per gallon)				Volumes (bbls)(a)
2015		$	1.2481				36,000

Mt Belvieu Iso-Butane Swaps

 

Production Period Ended December 31,		Average Fixed Price (per gallon)				Volumes (bbls)(a)
2015		$	1.2631				36,000

Mt Belvieu Natural Gasoline Swaps

 

Production Period Ended December 31,		Average Fixed Price (per gallon)				Volumes (bbls)(a)
2015		$	1.9831				120,000

 

14