Targa Energy LP - FORM 8-K - EX-99.1

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8-K - FORM 8-K - Targa Energy LP	d683374d8k.htm

Exhibit 99.1

NEWS RELEASE


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

ATLAS ENERGY, L.P. REPORTS OPERATING AND FINANCIAL RESULTS

FOR THE FOURTH QUARTER AND FULL YEAR 2013

Philadelphia, PA – February 27, 2014 - Atlas Energy, L.P. (NYSE: ATLS) (“Atlas Energy” or “ATLS”) today reported operating and financial results for the fourth quarter and full year 2013.

Edward E. Cohen, Chief Executive Officer of Atlas Energy, stated, “For the Atlas Energy group of companies, 2013 was a good year, although not without challenge, and 2014 should be even better. Our E&P operations at Atlas Resource grew substantially in 2013 both from development in attractive basins, and from accretive acquisitions, and we anticipate future favorable developments organically and corporately. Atlas Pipeline now has state-of-the-art processing plants, growing rapidly, easily scalable, located in the greatest NGL growth areas in North America — in the Permian and Eagle Ford basins in Texas, and in the SCOOP and Mississippi Lime areas in Oklahoma. We look to 2014 — and to 2015 — with high confidence.”

ATLS declared a cash distribution of $0.46 per limited partner unit for the fourth quarter 2013, which represents a $0.16 per unit, or 53%, increase over the prior year fourth quarter. The fourth quarter 2013 ATLS distribution was paid on February 19, 2014 to holders of record as of February 10, 2014. ATLS anticipates cash distributions to be $1.95 to $2.45 per common unit for full year 2014, based on distribution guidance provided by its subsidiaries, Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”) and Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL”).

* * *

Distributions from Subsidiaries

•

On January 29, 2014, ARP, Atlas Energy’s E&P subsidiary, declared a cash distribution of $0.58 per limited partner unit for the fourth quarter 2013, an approximate 4% increase over the third quarter 2013 and a 21% increase from the prior year fourth quarter distribution. This distribution was paid on February 14, 2014 to holders of record as of February 6, 2014. ATLS received approximately $17.2 million of cash distributions based upon ARP’s fourth quarter 2013 distribution.

•

On January 28, 2014, APL, Atlas Energy’s midstream subsidiary, declared a cash distribution for the fourth quarter 2013 of $0.62 per unit, a 9% increase from APL’s prior year quarter. This distribution was paid on February 14, 2014 to holders of record as of February 6, 2014. ATLS received approximately $9.7 million of cash distributions based upon APL’s fourth quarter 2013 distribution.

Recent Events

GeoMet Transaction

On February 14, 2014, ARP announced that it entered into a definitive agreement to acquire approximately 70 billion cubic feet equivalents of natural gas proved reserves in West Virginia and Virginia from GeoMet, Inc. (OTCQB: GMET) and certain of its subsidiaries (collectively, “GeoMet”) for $107 million, with an effective date of January 1, 2014. The acquisition is expected to be immediately accretive to ARP’s distributable cash flow per unit. The purchase price is subject to customary adjustments to implement the effective date. The transaction is subject to, among other items, approval from GeoMet’s stockholders.

ARP expects to benefit from the mature, low-decline production from the acquired assets, which will complement its existing oil and gas base. The assets consist of approximately proved reserves in West Virginia and Virginia, and are 100% natural gas and proved developed. Current net production on the assets is approximately 22 million cubic feet equivalents per day (“Mmcfed”) from over 400 active wells, with a current expected decline rate of approximately 10-12%. Current production costs include lease operating costs of approximately $1.20 per thousand cubic feet (“mcf”), production and ad valorem taxes of approximately 10%, and transportation and gathering costs of approximately $0.40/mcf.

ARP’s New Monthly Distribution Policy

ARP declared an initial monthly distribution of $0.1933 per common unit for the month of January 2014 on February 24, 2014, which is payable on March 17, 2014 to holders of record as of March 7, 2014. ARP previously announced that its board of directors had approved the modification of its distribution payment practice to a monthly distribution program. Future monthly cash distributions will be paid within 45 days following the end of each respective monthly period. ARP management and the board of directors determined that a monthly distribution policy more closely aligned the realization and distribution of cash flow with investors’ interests.

Atlas Energy’s Arkoma Production

ATLS had net production of approximately 12.2 million cubic feet equivalents per day in the fourth quarter 2013 primarily from its Arkoma assets, with production margin of approximately $2.4 million in the period. ATLS acquired this production in July 2013.

ARP’s Fourth Quarter 2013 Highlights

•

Average net daily production for the fourth quarter 2013 was 259.8 Mmcfed, an increase of approximately 97% from the prior year comparable quarter. The increase in net production from the fourth quarter 2012 was due primarily to the acquisition of 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 fourth quarter 2013 in several of ARP’s key operating areas, including the Mississippi Lime and Marble Falls.

•

During 2013, ARP continued development on its acreage positions located in several attractive U.S. oil and natural gas basins. ARP turned into line the following number of gross wells per region during 2013: 82 wells in the Marble Falls/Barnett Shale region; 21 wells in the Mississippi Lime play in northwestern Oklahoma; 9 wells in the Marcellus Shale (8 of which were in Lycoming County, PA); and 5 wells in the Utica Shale play in Harrison County, OH.

•

In the fourth quarter 2013, ARP experienced adverse weather conditions in several of its operating areas, namely in Texas. As a result, oil and gas production from certain areas was restricted for periods of time, which directly affected realized production margin for the fourth quarter 2013. ARP has estimated the impact was approximately $2.5 million to $3.0 million to Distributable Cash Flow from weather-related issues in the quarter.

ATLS owns 100% of the general partner Class A units and the incentive distribution rights, and a 37% limited partner interest in ARP. ATLS’ financial results are presented on a consolidated basis with those of ARP. Non-controlling interests in ARP are reflected as income (expense) in ATLS’ consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. A consolidating statement of operations and balance sheet have also been provided in the financial tables to this release for the comparable periods presented. Please refer to the ARP fourth quarter 2013 earnings release for additional details on its financial results.

APL’s Fourth Quarter 2013 Highlights

During the fourth quarter 2013, APL increased inlet volumes on its gathering and processing systems in the Mid Continent region, primarily in Texas and Oklahoma. APL processed an average of over 1.38 billion cubic feet per day (“Bcfd”) of natural gas in the fourth quarter 2013 amongst its WestOK, WestTX, Velma, Arkoma and SouthTX systems, approximately 38% higher than the prior year comparable quarter’s volumes. APL processed over 118,000 barrels per day (“bpd”) of natural gas liquids generated from its five processing systems in highly prolific oil & gas basins.

ATLS owns a 2.0% general partner interest, all of the incentive distribution rights, and a 6.2% common limited partner interest in APL. ATLS’ financial results are presented on a consolidated basis with those of APL. Non-controlling interests in APL are reflected as income (expense) in ATLS’ consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. A consolidating statement of operations and balance sheet have also been provided in the financial tables to this release for the comparable periods presented. Please refer to the APL fourth quarter 2013 earnings release for additional details on its financial results.

Hedge Positions

In connection with its acquisition from EP Energy in July 2013 of natural gas proved reserves in the Arkoma Basin (“Arkoma Assets”), ATLS entered into direct natural gas hedge positions for a substantial portion of its production through 2018. A summary of ATLS’s derivative positions as of February 27, 2014 is provided in the financial tables of this release.

Corporate Expenses

•

Cash general and administrative expense, excluding amounts attributable to APL and ARP, was $1.6 million for the fourth quarter 2013, which was generally consistent with the third quarter 2013. Please refer to the consolidating statements of operations provided in the financial tables of this release.

•

Cash interest expense, excluding amounts attributable to APL and ARP, was $4.1 million for the fourth quarter 2013, an increase of $0.7 million compared to the third quarter 2013. The increase was due a full quarter’s interest expense on ATLS’ $240 million term loan credit facility, which was entered into in July 2013 to fund the acquisition of the Arkoma Assets from EP Energy and the purchase of the Class C convertible preferred units from ARP. As of December 31, 2013, ATLS had $240 million of total debt, with no borrowings outstanding under its $50 million revolving credit facility, and a cash position of approximately $18 million.

* * *

Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Energy, L.P.’s fourth quarter 2013 results on Friday, February 28, 2014 at 9:00 am ET by going to the Investor Relations section of Atlas Energy’s website at www.atlasenergy.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 Energy website and telephonically beginning at 1:00 p.m. ET on February 28, 2014 by dialing 888-286-8010, passcode: 19431975.

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 at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 13,000 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 ARP’s website at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 14 active gas processing plants, 18 gas treating facilities, as well as approximately 11,200 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 APL’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Cautionary Note Regarding Forward-Looking Statements

This press release 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. ATLS 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, planned expansions of capacity and other capital expenditures, distribution amounts, ATLS’ 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; ability to realize the benefits of its acquisition; changes in commodity prices and hedge positions; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ATLS’ 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 ATLS’, ARP’s and APL’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 ATLS assumes no obligation to update such statements, except as may be required by applicable law.

ATLAS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except per unit data)


	Three Months Ended						Years Ended
	December 31,						December 31,
	2013			2012			2013			2012
Revenues:
Gas and oil production	$	97,716		$	31,578		$	273,906		$	92,901
Well construction and completion		75,590			39,219			167,883			131,496
Gathering and processing		600,724			360,386			2,139,694			1,219,815
Administration and oversight		3,354			3,224			12,277			11,810
Well services		4,789			4,697			19,492			20,041
Gain (loss) on mark-to-market derivatives⁽¹⁾		(19,271	)		(4,965	)		(28,764	)		31,940
Other, net		(1,273	)		4,865			(6,973	)		13,440

Total revenues		761,629			439,004			2,577,515			1,521,443


Costs and expenses:
Gas and oil production		35,341			10,377			100,178			26,624
Well construction and completion		65,730			34,197			145,985			114,079
Gathering and processing		504,318			298,630			1,802,618			1,009,100
Well services		2,506			2,204			9,515			9,280
General and administrative		41,530			56,931			197,976			165,777
Chevron transaction expense		—			—			—			7,670
Depreciation, depletion and amortization		94,220			43,048			308,533			142,611
Asset impairment		81,880			9,507			81,880			9,507

Total costs and expenses		825,525			454,894			2,646,685			1,484,648


Operating income (loss)		(63,896	)		(15,890	)		(69,170	)		36,795

Gain (loss) on asset sales and disposal		1,048			39			(2,506	)		(6,980	)
Interest expense		(40,727	)		(15,890	)		(132,581	)		(46,520	)
Loss on early extinguishment of debt		—			—			(26,601	)		—


Net loss before tax		(103,575	)		(31,741	)		(230,858	)		(16,705	)
Income tax benefit (expense)		1,406			(176	)		2,260			(176	)

Net loss		(102,169	)		(31,917	)		(228,598	)		(16,881	)
Loss (income) attributable to non-controlling interests		75,169			17,042			153,231			(35,532	)

Net loss attributable to common limited partners	$	(27,000	)	$	(14,875	)	$	(75,367	)	$	(52,413	)


Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.53	)	$	(0.29	)	$	(1.47	)	$	(1.02	)

Weighted average common limited partner units outstanding:
Basic and Diluted		51,410			51,359			51,387			51,327

⁽¹⁾	Consists principally of hydrocarbon derivative gains / (losses) that relate to the operating activities of ATLS’s consolidated subsidiary, APL. The underlying hydrocarbon derivatives do not represent present or potential future obligations of ATLS.

ATLAS ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)


	December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	23,501	$	36,780
Accounts receivable		279,464		196,249
Current portion of derivative asset		2,066		35,351
Subscriptions receivable		47,692		55,357
Prepaid expenses and other		27,612		45,255

Total current assets		380,335		368,992

Property, plant and equipment, net		4,910,875		3,502,609
Intangible assets, net		697,234		200,680
Investment in joint venture		248,301		86,002
Goodwill, net		400,356		351,069
Long-term derivative asset		30,868		16,840
Long-term derivative receivable from Drilling Partnerships		863		—
Other assets, net		123,809		71,002

	$	6,792,641	$	4,597,194


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Current portion of long-term debt	$	2,924	$	10,835
Accounts payable		149,279		119,028
Liabilities associated with drilling contracts		49,377		67,293
Accrued producer liabilities		152,309		109,725
Current portion of derivative liability		17,630		—
Current portion of derivative payable to Drilling Partnerships		2,676		11,293
Accrued interest		47,402		11,556
Accrued well drilling and completion costs		40,899		47,637
Accrued liabilities		84,759		103,291

Total current liabilities		547,255		480,658

Long-term debt, less current portion		2,886,120		1,529,508
Long-term derivative liability		387		888
Long-term derivative payable to Drilling Partnerships		—		2,429
Deferred income taxes, net		33,290		30,258
Asset retirement obligations and other		102,713		73,605

Commitments and contingencies

Partners’ Capital:
Common limited partners’ interests		361,511		456,171
Accumulated other comprehensive income		10,338		9,699

		371,849		465,870
Non-controlling interests		2,851,027		2,013,978

Total partners’ capital		3,222,876		2,479,848

	$	6,792,641	$	4,597,194

ATLAS ENERGY, L.P.

Financial and Operating Highlights

(unaudited)


	Three Months Ended						Years Ended
	December 31,						December 31,
	2013			2012			2013			2012
Net loss attributable to common limited partners per unit - basic	$	(0.53	)	$	(0.29	)	$	(1.47	)	$	(1.02	)

Cash distributions paid per unit⁽¹⁾	$	0.46		$	0.30		$	1.67		$	1.07

Production volume:⁽²⁾⁽³⁾
ATLAS ENERGY:
Natural gas (Mcfd)		12,007			—			5,106			—
Oil (Bpd)		28			—			7			—
Natural gas liquids (Bpd)		10			—			3			—

Total (Mcfed)		12,238			—			5,164			—

ATLAS RESOURCES:
Natural gas (Mcfd)		229,931			95,845			158,886			69,408
Oil (Bpd)		1,413			447			1,329			330
Natural gas liquids (Bpd)		3,569			1,935			3,473			974

Total (Mcfed)		259,821			110,137			187,701			77,232

TOTAL:
Natural gas (Mcfd)		241,938			95,845			163,992			69,408
Oil (Bpd)		1,441			447			1,336			330
Natural gas liquids (Bpd)		3,579			1,935			3,476			974

Total (Mcfed)		272,059			110,137			192,866			77,232


Average sales prices:⁽³⁾
Natural gas (per Mcf)⁽⁴⁾	$	3.63		$	3.04		$	3.48		$	3.29
Oil (per Bbl)⁽⁵⁾	$	90.57		$	90.76		$	91.02		$	94.02
Natural gas liquids (per gallon)	$	0.73		$	0.73		$	0.68		$	0.76

Production costs:⁽³⁾⁽⁶⁾
ATLAS ENERGY:
Lease operating expenses per Mcfe	$	0.84		$	—		$	0.81		$	—
Production taxes per Mcfe		0.22			—			0.22			—
Transportation and compression expenses per Mcfe		0.51			—			0.53			—

Total production costs per Mcfe	$	1.58		$	—		$	1.56		$	—

ATLAS RESOURCES:
Lease operating expenses per Mcfe	$	1.03		$	0.88		$	1.09		$	0.82
Production taxes per Mcfe		0.18			0.14			0.18			0.12
Transportation and compression expenses per Mcfe		0.28			0.18			0.24			0.24

Total production costs per Mcfe	$	1.49		$	1.19		$	1.50		$	1.19

TOTAL:
Lease operating expenses per Mcfe	$	1.02		$	0.88		$	1.08		$	0.82
Production taxes per Mcfe		0.18			0.14			0.18			0.12
Transportation and compression expenses per Mcfe		0.29			0.18			0.25			0.24

Total production costs per Mcfe	$	1.50		$	1.19		$	1.50		$	1.19


ATLAS PIPELINE:
Production volume:⁽³⁾
Gathered gas volume(Mcfd)		1,486,196			1,100,266			1,426,835			1,026,996
Processed gas volume (Mcfd)		1,385,589			1,001,883			1,314,596			922,715
Residue gas volume (Mcfd)		1,173,169			846,794			1,112,137			777,605
NGL volume (Bpd)		118,809			80,120			114,690			76,807
Condensate volume (Bpd)		3,490			3,044			4,146			3,415
Average sales prices:⁽³⁾
Natural gas (per Mcf)	$	3.39		$	3.18		$	3.44		$	2.62
Condensate (per Bbl)	$	88.71		$	80.75		$	91.90		$	87.88
Natural gas liquids (per gallon)	$	0.99		$	0.90		$	0.91		$	0.90

⁽¹⁾	Represents the cash distributions declared per limited partner unit for the respective period and paid by ATLS within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

⁽²⁾

Production quantities consist of the sum of (i) the proportionate share of production from wells in which ATLS and ARP have a direct interest, based on the 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⁾

Average sales price for natural gas before the effects of financial hedging was $3.35 per Mcf and $2.98 per Mcf for the three months ended December 31, 2013 and 2012, respectively, and $3.25 per Mcf and $2.60 per Mcf for the years ended December 31, 2013 and 2012, respectively. These amounts exclude the impact of subordination of ARP’s production revenues to investor partners within its investor partnerships. Including the effects of this subordination, average natural gas sales prices were $3.40 per Mcf ($3.12 per Mcf before the effects of financial hedging) and $2.54 per Mcf ($2.48 per Mcf before the effects of financial hedging) for the three months ended December 31, 2013 and 2012, respectively, and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging) and $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) for the years ended December 31, 2013 and 2012, respectively.

⁽⁵⁾	Average sales price for oil before the effects of financial hedging was $94.15 per barrel and $87.55 per barrel for the three months ended December 31, 2013 and 2012, respectively, and $95.86 per barrel and $91.32 per barrel for the years ended December 31, 2013 and 2012, respectively.

⁽⁶⁾

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 and compression 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, total lease operating expenses per Mcfe were $0.94 per Mcfe ($1.41 per Mcfe for total production costs) and $0.71 per Mcfe ($1.02 per Mcfe for total production costs) for the three months ended December 31, 2013 and 2012, respectively, and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) and $0.58 per Mcfe ($0.94 per Mcfe for total production costs) for the years ended December 31, 2013 and 2012, respectively.

ATLAS ENERGY, L.P.

Financial Information

(unaudited; in thousands except per unit amounts)


	Three Months Ended						Years Ended
	December 31,						December 31,
	2013			2012			2013			2012
Reconciliation of net loss to non-GAAP measures⁽¹⁾:
Net income (loss)	$	(102,169	)	$	(31,917	)	$	(228,598	)	$	(16,881	)
E&P Operations EBITDA prior to spinoff on March 5, 2012⁽²⁾		—			—			—			9,111
Atlas Resource net loss attributable to ATLS common limited partners		12,697			11,274			32,463			34,718
Atlas Resource cash distributions earned by ATLS⁽³⁾		17,224			10,680			58,347			31,270
Atlas Pipeline net (income) loss attributable to ATLS common limited partners		1,969			(2,501	)		(1,644	)		(15,343	)
Atlas Pipeline cash distributions earned by ATLS⁽³⁾		9,662			6,454			36,057			23,024
Development Subsidiary net loss attributable to ATLS common limited partners		1,760			—			4,418			—
Development Subsidiary cash distributions earned by ATLS⁽³⁾		26			—			26			—
Non-recurring spinoff and acquisition costs		320			—			2,151			8,370
Amortization of deferred finance costs		459			51			1,124			230
Depreciation, depletion and amortization		1,689			—			3,020			—
Non-cash stock compensation expense		5,247			4,611			22,971			18,237
Maintenance capital expenditures⁽⁴⁾		(300	)		—			(500	)		(1,231	)
Other non-cash adjustments		73			(172	)		(2,027	)		(591	)
Amortization of premiums paid on swaption derivative contracts associated with asset acquisition⁽⁵⁾		—			—			2,287			—
Loss (income) attributable to non-controlling interests		75,169			17,042			153,231			(35,532	)

Distributable Cash Flow⁽¹⁾	$	23,826		$	15,522		$	83,326		$	55,382


Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Atlas Resource Cash Distributions Earned⁽³⁾:
Limited Partner Units	$	14,333		$	10,062		$	50,183		$	29,975
Class A Units (2%)		794			469			2,755			1,146
Incentive Distribution Rights		2,097			149			5,409			149

Total Atlas Resource Cash Distributions Earned⁽³⁾		17,224			10,680			58,347			31,270

per limited partner unit	$	0.58		$	0.48		$	2.19		$	1.43

Atlas Pipeline Cash Distributions Earned⁽³⁾:
Limited Partner Units		3,568			3,337			14,098			13,061
General Partner 2% Interest		1,126			815			4,281			2,776
Incentive Distribution Rights		4,968			2,302			17,678			7,187

Total Atlas Pipeline Cash Distributions Earned⁽³⁾		9,662			6,454			36,057			23,024

per limited partner unit	$	0.62		$	0.58		$	2.45		$	2.27

Development Subsidiary Cash Distributions Earned⁽³⁾		26			—			26			—

Total Cash Distributions Earned		26,912			17,134			94,430			54,294

Production Margin		2,427			—			3,960			—
E&P Operations Adjusted EBITDA prior to spinoff on March 5, 2012⁽²⁾		—			—			—			9,111
Cash general and administrative expenses⁽⁶⁾		(1,605	)		(1,531	)		(8,256	)		(7,441	)
Other, net		458			1			1,188			984

Adjusted EBITDA⁽¹⁾		28,192			15,604			91,322			56,948
Cash interest expense⁽⁷⁾		(4,066	)		(82	)		(7,496	)		(335	)
Maintenance capital expenditures⁽⁴⁾		(300	)		—			(500	)		(1,231	)

Distributable Cash Flow⁽¹⁾	$	23,826		$	15,522		$	83,326		$	55,382


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⁽⁸⁾		—			—			1,851			—

Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner⁽⁹⁾	$	23,826		$	15,522		$	85,177		$	55,382


Distributions Paid⁽¹⁰⁾	$	23,650		$	15,410		$	85,829		$	54,937
per limited partner unit	$	0.46		$	0.30		$	1.67		$	1.07

Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders⁽¹¹⁾	$	176		$	112		$	(652	)	$	445

⁽¹⁾

Although not prescribed under generally accepted accounting principles (“GAAP”), ATLS’ management believes the presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow is relevant and useful because it helps ATLS’ 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, ATLS 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. ATLS 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 ATLS’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 ATLS’ management and by external users of ATLS’ financial statements such as investors, lenders under its credit facilities, research analysts, rating agencies and others to assess its:

•

Operating performance as compared to other publicly traded partnerships and other companies in the upstream and midstream energy sectors, 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 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. ATLS defines EBITDA as net income (loss) plus the following adjustments:

•

Interest expense;

•

Income tax expense;

•

Depreciation, depletion and amortization.

ATLS defines Adjusted EBITDA as EBITDA plus the following adjustments:

•

Cash distributions paid by ARP and APL within 45 days after the end of the respective quarter, based upon their distributable cash flow generated during that quarter;

•

Asset impairments;

•

Acquisition and related costs;

•

Non-cash stock compensation;

•

(Gains) losses on asset disposal;

•

Cash proceeds received from monetization of derivative transactions;

•

Amortization of premiums paid on swaption derivative contracts; and

•

Other items.

ATLS 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. ATLS defines DCF as Adjusted EBITDA less the following adjustments:

•

Cash interest expense; and

•

Maintenance capital expenditures.

⁽²⁾

Represents the E&P Operations Adjusted EBITDA generated and maintenance capital expenditures incurred by ATLS on a stand-alone basis prior to the transfer of its E&P assets to ARP on March 5, 2012 for the year ended December 31, 2012.

⁽³⁾

Represents the cash distribution paid by ARP, APL and its new Development Subsidiary within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

⁽⁴⁾

Production from oil and gas assets naturally decline in future periods and, as such, ATLS 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. ATLS 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. ATLS 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 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. Generally, 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. ATLS 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.

⁽⁵⁾

Swaption derivative contracts grant ATLS 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 ATLS paid to enter into swaption derivative contracts for certain acquired volumes over the option period. Generally, ATLS 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. ATLS 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.

⁽⁶⁾

Excludes non-cash stock compensation expense and certain non-recurring spinoff costs and acquisition and related costs.

⁽⁷⁾

Excludes non-cash amortization of deferred financing costs.

⁽⁸⁾

These amounts reflect net cash proceeds received from the effective date through the closing date of the EP Energy assets acquired, less estimated and pro forma amounts of maintenance capital expenditures and financing costs. The management of ATLS believes these amounts are critical in its evaluation of Distributable Cash Flow 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 year ended December 31, 2013, such amounts include pro forma net cash generated by the EP Energy assets of $3.8 million from April 1, 2013 to July 31, 2013, less pro forma interest expense of $1.5 million and estimated maintenance capital expenditures of $0.5 million.

⁽⁹⁾

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 $28.2 million and $15.6 million for the three months ended December 31, 2013 and 2012, respectively, and $93.2 million and $56.9 million for the years ended December 31, 2013 and 2012, respectively

⁽¹⁰⁾

Represents the cash distribution paid within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

⁽¹¹⁾

ATLS 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. ATLS’ 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 which affect it, ARP and APL and the cash distributions it receives from these subsidiaries, including but not limited to future commodity price and interest rate movements, variability of operating asset performance, weather effects, and financial leverage. ATLS 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 ENERGY, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)


	December 31, 2013
	Atlas			Atlas			Atlas
	Energy			Resource			Pipeline			Consolidated
Total debt	$	239,400		$	942,334		$	1,707,310		$	2,889,044
Less: Cash		(16,759	)		(1,828	)		(4,914	)		(23,501	)

Total net debt		222,641			940,506			1,702,396			2,865,543

Partners’ capital		371,849			1,067,291			2,259,905			3,222,876	⁽¹⁾


Total capitalization	$	594,490		$	2,007,797		$	3,962,301		$	6,088,419


Ratio of net debt to capitalization		0.37x

⁽¹⁾	Net of eliminated amounts.


	December 31, 2012
	Atlas			Atlas			Atlas
	Energy			Resource			Pipeline			Consolidated
Total debt	$	9,000		$	351,425		$	1,179,918		$	1,540,343
Less: Cash		(10,194	)		(23,188	)		(3,398	)		(36,780	)

Total net debt/(cash)		(1,194	)		328,237			1,176,520			1,503,563

Partners’ capital		465,870			862,006			1,606,408			2,479,848	⁽²⁾


Total capitalization	$	464,676		$	1,190,243		$	2,782,928		$	3,983,411


Ratio of net debt to capitalization		0.00x

⁽²⁾	Net of eliminated amounts.

ATLAS ENERGY, L.P.

Hedge Position Summary – Directly-Held E&P Assets

(as of February 28, 2014)

Natural Gas


Fixed Price Swaps
Production Period Ended December 31,	Average Fixed Price (per mmbtu)^(a)		Volumes (mmbtus)^(a)
2014	$	4.18		2,760,000
2015	$	4.30		2,280,000
2016	$	4.43		1,440,000
2017	$	4.59		1,200,000
2018	$	4.80		420,000

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

ATLAS ENERGY, L.P.

CONSOLIDATING STATEMENTS OF OPERATIONS

(unaudited; in thousands)

Three Months Ended December 31, 2013


	Atlas Energy			Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
Revenues:
Gas and oil production	$	4,423		$	93,293		$	—		$	—		$	97,716
Well construction and completion		—			75,590			—			—			75,590
Gathering and processing		—			4,037			596,768			(81	)		600,724
Administration and oversight		—			3,354			—			—			3,354
Well services		—			4,789			—			—			4,789
Loss on mark-to-market derivatives		—			—			(19,271	)		—			(19,271	)
Other, net		385			133			(1,791	)		—			(1,273	)

Total revenues		4,808			181,196			575,706			(81	)		761,629


Costs and expenses:
Gas and oil production		1,774			33,567			—			—			35,341
Well construction and completion		—			65,730			—			—			65,730
Gathering and processing		—			4,245			500,154			(81	)		504,318
Well services		—			2,506			—			—			2,506
General and administrative		10,189			14,296			17,045			—			41,530
Depreciation, depletion and amortization		1,822			51,702			40,696			—			94,220
Asset impairment		—			38,014			43,866			—			81,880

Total costs and expenses		13,785			210,060			601,761			(81	)		825,525


Operating income (loss)		(8,977	)		(28,864	)		(26,055	)		—			(63,896	)

Gain on asset sales and disposal		—			1,048			—			—			1,048
Interest expense		(4,525	)		(12,179	)		(24,023	)		—			(40,727	)
Loss on early extinguishment of debt		—			—			—			—			—


Net loss before tax		(13,502	)		(39,995	)		(50,078	)		—			(103,575	)
Income tax benefit		—			—			1,406			—			1,406

Net loss		(13,502	)		(39,995	)		(48,672	)		—			(102,169	)
(Income) loss attributable to non-controlling interests		—			—			(2,282	)		77,451			75,169

Net loss attributable to common limited partners	$	(13,502	)	$	(39,995	)	$	(50,954	)	$	77,451		$	(27,000	)

ATLAS ENERGY, L.P.

CONSOLIDATING STATEMENTS OF OPERATIONS

(unaudited; in thousands)

Three Months Ended December 31, 2012


	Atlas Energy			Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
Revenues:
Gas and oil production	$	—		$	31,578		$	—		$	—		$	31,578
Well construction and completion		—			39,219			—			—			39,219
Gathering and processing		—			5,956			354,508			(78	)		360,386
Administration and oversight		—			3,224			—			—			3,224
Well services		—			4,697			—			—			4,697
Loss on mark-to-market derivatives		—			—			(4,965	)		—			(4,965	)
Other, net		173			66			4,626			—			4,865

Total revenues		173			84,740			354,169			(78	)		439,004


Costs and expenses:
Gas and oil production		—			10,377			—			—			10,377
Well construction and completion		—			34,197			—			—			34,197
Gathering and processing		—			6,306			292,402			(78	)		298,630
Well services		—			2,204			—			—			2,204
General and administrative		6,142			20,696			30,093			—			56,931
Depreciation, depletion and amortization		—			18,734			24,314			—			43,048
Asset impairment		—			9,507			—			—			9,507

Total costs and expenses		6,142			102,021			346,809			(78	)		454,894


Operating income (loss)		(5,969	)		(17,281	)		7,360			—			(15,890	)

Gain on asset sales and disposal		—			39			—			—			39
Interest expense		(133	)		(1,666	)		(14,091	)		—			(15,890	)


Net loss before tax		(6,102	)		(18,908	)		(6,731	)		—			(31,741	)
Income tax expense		—			—			(176	)		—			(176	)

Net loss		(6,102	)		(18,908	)		(6,907	)		—			(31,917	)
(Income) loss attributable to non-controlling interests		—			—			(1,902	)		18,944			17,042

Net income (loss) attributable to common limited partners	$	(6,102	)	$	(18,908	)	$	(8,809	)	$	18,944		$	(14,875	)

ATLAS ENERGY, L.P.

CONSOLIDATING STATEMENTS OF OPERATIONS

(unaudited; in thousands)

Year Ended December 31, 2013


	Atlas Energy			Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
Revenues:
Gas and oil production	$	7,123		$	266,783		$	—		$	—		$	273,906
Well construction and completion		—			167,883			—			—			167,883
Gathering and processing		—			15,676			2,124,321			(303	)		2,139,694
Administration and oversight		—			12,277			—			—			12,277
Well services		—			19,492			—			—			19,492
Loss on mark-to-market derivatives		—			—			(28,764	)		—			(28,764	)
Other, net		927			(14,456	)		6,556			—			(6,973	)

Total revenues		8,050			467,655			2,102,113			(303	)		2,577,515


Costs and expenses:
Gas and oil production		2,941			97,237			—			—			100,178
Well construction and completion		—			145,985			—			—			145,985
Gathering and processing		—			18,012			1,784,909			(303	)		1,802,618
Well services		—			9,515			—			—			9,515
General and administrative		39,052			78,063			80,861			—			197,976
Depreciation, depletion and amortization		3,153			136,763			168,617			—			308,533
Asset impairment		—			38,014			43,866			—			81,880

Total costs and expenses		45,146			523,589			2,078,253			(303	)		2,646,685


Operating income (loss)		(37,096	)		(55,934	)		23,860			—			(69,170	)

Loss on asset sales and disposal		—			(987	)		(1,519	)		—			(2,506	)
Interest expense		(8,620	)		(34,324	)		(89,637	)		—			(132,581	)
Loss on early extinguishment of debt		—			—			(26,601	)		—			(26,601	)


Net loss before tax		(45,716	)		(91,245	)		(93,897	)		—			(230,858	)
Income tax benefit		—			—			2,260			—			2,260

Net loss		(45,716	)		(91,245	)		(91,637	)		—			(228,598	)
(Income) loss attributable to non-controlling interests		—			—			(6,975	)		160,206			153,231

Net loss attributable to common limited partners	$	(45,716	)	$	(91,245	)	$	(98,612	)	$	160,206		$	(75,367	)

ATLAS ENERGY, L.P.

CONSOLIDATING STATEMENTS OF OPERATIONS

(unaudited; in thousands)

Year Ended December 31, 2012


	Atlas Energy			Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
Revenues:
Gas and oil production	$	—		$	92,901		$	—		$	—		$	92,901
Well construction and completion		—			131,496			—			—			131,496
Gathering and processing		—			16,267			1,203,983			(435	)		1,219,815
Administration and oversight		—			11,810			—			—			11,810
Well services		—			20,041			—			—			20,041
Gain on mark-to-market derivatives		—			—			31,940			—			31,940
Other, net		1,575			(4,886	)		16,751			—			13,440

Total revenues		1,575			267,629			1,252,674			(435	)		1,521,443


Costs and expenses:
Gas and oil production		—			26,624			—			—			26,624
Well construction and completion		—			114,079			—			—			114,079
Gathering and processing		—			19,491			990,044			(435	)		1,009,100
Well services		—			9,280			—			—			9,280
General and administrative		34,048			69,123			62,606			—			165,777
Chevron transaction expense		—			7,670			—			—			7,670
Depreciation, depletion and amortization		—			52,582			90,029			—			142,611
Asset impairment		—			9,507			—			—			9,507

Total costs and expenses		34,048			308,356			1,142,679			(435	)		1,484,648


Operating income (loss)		(32,473	)		(40,727	)		109,995			—			36,795

Loss on asset sales and disposal		—			(6,980	)		—			—			(6,980	)
Interest expense		(565	)		(4,195	)		(41,760	)		—			(46,520	)


Net income (loss) before tax		(33,038	)		(51,902	)		68,235			—			(16,705	)
Income tax expense		—			—			(176	)		—			(176	)

Net income (loss)		(33,038	)		(51,902	)		68,059			—			(16,881	)
Income attributable to non-controlling interests		—			—			(6,010	)		(29,522	)		(35,532	)

Net income (loss) attributable to common limited partners	$	(33,038	)	$	(51,902	)	$	62,049		$	(29,522	)	$	(52,413	)

ATLAS ENERGY, L.P.

CONDENSED CONSOLIDATING BALANCE SHEETS

(unaudited; in thousands)

December 31, 2013


	Atlas Energy		Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	16,759	$	1,828		$	4,914		$	—		$	23,501
Accounts receivable		1,345		58,822			219,297			—			279,464
Receivable from (advances from) affiliates		29,654		(26,742	)		(2,912	)		—			—
Current portion of derivative asset		1		1,891			174			—			2,066
Subscriptions receivable		—		47,692			—			—			47,692
Prepaid expenses and other		122		10,097			17,393			—			27,612

Total current assets		47,881		93,588			238,866			—			380,335

Property, plant and equipment, net		65,865		2,120,818			2,724,192			—			4,910,875
Intangible assets, net		—		963			696,271			—			697,234
Investment in joint venture		—		—			248,301			—			248,301
Goodwill, net		—		31,784			368,572			—			400,356
Long-term derivative asset		1,514		27,084			2,270			—			30,868
Long-term derivative receivable from Drilling Partnerships		—		863			—			—			863
Investment in subsidiaries		476,169		—			—			(476,169	)		—
Other assets, net		35,390		41,958			46,461			—			123,809

	$	626,819	$	2,317,058		$	4,324,933		$	(476,169	)	$	6,792,641

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Current portion of long-term debt	$	2,400	$	—		$	524		$	—		$	2,924
Accounts payable		882		69,346			79,051			—			149,279
Liabilities associated with drilling contracts		—		49,377			—			—			49,377
Accrued producer liabilities		—		—			152,309			—			152,309
Current portion of derivative liability		33		6,353			11,244			—			17,630
Current portion of derivative payable to Drilling Partnerships		—		2,676			—			—			2,676
Accrued interest		43		20,622			26,737			—			47,402
Accrued well drilling and completion costs		418		40,481			—			—			40,899
Accrued liabilities		9,192		28,118			47,449			—			84,759

Total current liabilities		12,968		216,973			317,314			—			547,255

Long-term debt, less current portion		237,000		942,334			1,706,786			—			2,886,120
Long-term derivative liability		—		67			320			—			387
Deferred income taxes, net		—		—			33,290			—			33,290
Asset retirement obligations and other		5,002		90,393			7,318			—			102,713

Partners’ Capital:
Common limited partners’ interests		361,511		1,041,592			2,200,645			(3,242,237	)		361,511
Accumulated other comprehensive income		10,338		25,699			—			(25,699	)		10,338

		371,849		1,067,291			2,200,645			(3,267,936	)		371,849
Non-controlling interests		—		—			59,260			2,791,767			2,851,027

Total partners’ capital		371,849		1,067,291			2,259,905			(476,169	)		3,222,876

	$	626,819	$	2,317,058		$	4,324,933		$	(476,169	)	$	6,792,641

ATLAS ENERGY, L.P.

CONDENSED CONSOLIDATING BALANCE SHEETS

(unaudited; in thousands)

December 31, 2012


	Atlas Energy		Atlas Resource			Atlas Pipeline			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	10,194	$	23,188		$	3,398		$	—		$	36,780
Accounts receivable		5		38,718			157,526			—			196,249
Receivable from (advances from) affiliates		11,353		(5,853	)		(5,500	)		—			—
Current portion of derivative asset		—		12,274			23,077			—			35,351
Subscriptions receivable		—		55,357			—			—			55,357
Prepaid expenses and other		118		9,063			36,074			—			45,255

Total current assets		21,670		132,747			214,575			—			368,992

Property, plant and equipment, net		—		1,302,228			2,200,381			—			3,502,609
Intangible assets, net		—		1,320			199,360			—			200,680
Long-term derivative asset		—		8,898			7,942			—			16,840
Goodwill, net		—		31,784			319,285			—			351,069
Investment in joint venture		—		—			86,002			—			86,002
Investment in subsidiaries		454,436		—			—			(454,436	)		—
Other assets, net		22,287		16,122			32,593			—			71,002

	$	498,393	$	1,493,099		$	3,060,138		$	(454,436	)	$	4,597,194

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Current portion of long-term debt	$	—	$	—		$	10,835		$	—		$	10,835
Accounts payable		171		59,549			59,308			—			119,028
Liabilities associated with drilling contracts		—		67,293			—			—			67,293
Accrued producer liabilities		—		—			109,725			—			109,725
Current portion of derivative payable to Drilling Partnerships		—		11,293			—			—			11,293
Accrued interest		4		1,153			10,399			—			11,556
Accrued well drilling and completion costs		—		47,637			—			—			47,637
Accrued liabilities		21,304		24,235			57,752			—			103,291

Total current liabilities		21,479		211,160			248,019			—			480,658

Long-term debt, less current portion		9,000		351,425			1,169,083			—			1,529,508
Long-term derivative liability		—		888			—			—			888
Long-term derivative payable to Drilling Partnerships		—		2,429			—			—			2,429
Deferred income taxes, net		—		—			30,258			—			30,258
Asset retirement obligations and other		2,044		65,191			6,370			—			73,605

Partners’ Capital:
Common limited partners’ interests		456,171		840,437			1,539,177			(2,379,614	)		456,171
Accumulated other comprehensive income		9,699		21,569			—			(21,569	)		9,699

		465,870		862,006			1,539,177			(2,401,183	)		465,870
Non-controlling interests		—		—			67,231			1,946,747			2,013,978

Total partners’ capital		465,870		862,006			1,606,408			(454,436	)		2,479,848

	$	498,393	$	1,493,099		$	3,060,138		$	(454,436	)	$	4,597,194

ATLAS ENERGY, L.P.

Ownership Interests Summary


Atlas Energy Ownership Interests as of December 31, 2013:	Amount			Overall Ownership Interest Percentage

ATLAS RESOURCE:
General partner interest		100	%		2.0	%
Common units		20,962,485			31.3	%
Preferred units		3,749,986			5.6	%
Incentive distribution rights		100	%		N/A

Total Atlas Energy ownership interests in Atlas Resource					38.9	%


DEVELOPMENT SUBSIDIARY:
General partner interest		83.1	%		2.0	%
Common units		200,010			18.3	%
Incentive distribution rights		83.1	%		N/A

Total Atlas Energy ownership interests in Development Subsidiary					20.3	%


ATLAS PIPELINE:
General partner interest		100	%		2.0	%
Common units		5,754,253			6.1	%
Incentive distribution rights		100	%		N/A

Total Atlas Energy ownership interests in Atlas Pipeline					8.1	%


LIGHTFOOT CAPITAL PARTNERS, GP LLC:
Approximate general partner ownership interest					15.9	%
Approximate limited partner ownership interest					12.0	%

Targa Energy LP - FORM 8-K - EX-99.1 - February 28, 2014

Attached files

Targa Energy LP Reports