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ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES
COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)

	Three Months Ended		Years Ended
	December 31,		December 31,
Revenues:	2015	2014	2015	2014
Gas and oil production	$ 68,596	$ 133,302	$ 368,845	$ 475,758
Well construction and completion	12,840	46,647	76,505	173,564
Gathering and processing	1,385	2,820	7,431	14,107
Administration and oversight	511	3,492	7,812	15,564
Well services	5,254	6,518	23,822	24,959
Gain on mark-to-market derivatives	57,619	2,819	268,085	2,819
Other, net	408	572	993	1,739
Total revenues	146,613	196,170	753,493	708,510

Costs and expenses:
Gas and oil production	39,974	49,706	171,882	184,296
Well construction and completion	11,165	40,562	66,526	150,925
Gathering and processing	2,207	3,625	9,613	15,525
Well services	2,427	2,482	9,162	10,007
General and administrative	27,532	26,989	109,569	90,476
Depreciation, depletion and amortization	35,886	64,566	166,929	242,079
Asset impairment	294,444	580,654	973,981	580,654
Total costs and expenses	413,635	768,584	1,507,662	1,273,962

Operating loss	(267,022)	(572,414)	(754,169)	(565,452)

Loss on asset sales and disposal	(905)	(176)	(1,181)	(1,859)
Loss on extinguishment of debt	—	—	(4,726)	—
Interest expense	(29,430)	(21,961)	(125,658)	(73,435)

Net loss	(297,357)	(594,551)	(885,734)	(640,746)
Preferred unitholders' dividends	(1,014)	—	(3,360)	—
Loss attributable to non-controlling interests	228,905	437,611	649,316	471,439
Net loss attributable to unitholders'/owner's interests	$ (69,466)	$ (156,940)	$ (239,778)	$ (169,307)

Allocation of net loss attributable to unitholders'/owner's interests:
Portion applicable to owner's interest (period prior to the transfer of assets on February 27, 2015)	$ —	$ (156,940)	$ (10,475)	$ (169,307)
Portion applicable to unitholders' interest (period subsequent to the transfer of assets on February 27, 2015)	(69,466)	—	(229,303)	—
Net loss attributable to unitholders' /owner's interests	$ (69,466)	$ (156,940)	$ (239,778)	$ (169,307)

Net loss attributable to unitholders per common unit:
Basic	$ (2.67)	$ —	$ (8.82)	$ —
Diluted	$ (2.67)	$ —	$ (8.82)	$ —

Weighted average common units outstanding:
Basic	26,011	—	26,011	—
Diluted	26,011	—	26,011	—

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES
COMBINED CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)

	December 31,	December 31,
ASSETS	2015	2014
Current assets:
Cash and cash equivalents	$ 31,214	$ 58,358
Accounts receivable	65,920	115,290
Advances to affiliates	−	4,389
Current portion of derivative asset	159,763	144,259
Subscriptions receivable	19,877	32,398
Prepaid expenses and other	22,997	26,789
Total current assets	299,771	381,483

Property, plant and equipment, net	1,316,897	2,419,289
Intangible assets, net	456	691
Goodwill, net	13,639	13,639
Long-term derivative asset	198,371	130,602
Other assets, net	88,980	80,611
	$ 1,918,114	$ 3,026,315

LIABILITIES AND UNITHOLDERS'/OWNER'S EQUITY

Current liabilities:
Current portion of long-term debt	$ —	$ 1,500
Accounts payable	52,550	123,670
Liabilities associated with drilling contracts	21,483	40,611
Accrued interest	25,452	26,479
Accrued well drilling and completion costs	33,555	92,910
Accrued liabilities	45,014	170,786
Total current liabilities	178,054	455,956

Long-term debt, less current portion	1,607,182	1,541,085
Asset retirement obligations and other	124,919	114,059

Commitments and contingencies

Unitholders'/owner's equity:
Common unitholders' deficit	(99,788)	—
Series A preferred equity	37,515	—
Owner's equity	—	147,308
Accumulated other comprehensive income	4,284	54,008
	(57,989)	201,316
Non-controlling interests	65,948	713,899
Total unitholders'/owner's equity	7,959	915,215
	$ 1,918,114	$ 3,026,315

		ATLAS ENERGY GROUP, LLC
		Financial and Operating Highlights
		(unaudited)

	Three Months Ended			Years Ended
	December 31,			December 31,
	2015		2014	2015	2014

Net loss attributable to unitholders per common unit - basic	$ (2.67)		$ —	$ (8.82)	$ —


Production volume:⁽¹⁾⁽²⁾
ATLAS GROWTH:
Natural gas (Mcfd)	449		796	557	691
Oil (Bpd)	967		104	667	117
Natural gas liquids (Bpd)	71		99	81	88
Total (Mcfed)	6,679		2,018	5,047	1,920
ATLAS RESOURCE:
Natural gas (Mcfd)	203,121		239,690	216,613	238,054
Oil (Bpd)	4,898		5,440	5,139	3,436
Natural gas liquids (Bpd)	2,824		4,040	3,155	3,802
Total (Mcfed)	249,450		296,571	266,374	281,486
TOTAL:
Natural gas (Mcfd)	203,570		240,486	217,170	238,745
Oil (Bpd)	5,865		5,544	5,806	3,553
Natural gas liquids (Bpd)	2,895		4,140	3,236	3,891
Total (Mcfed)	256,129		298,590	271,421	283,406

Average realized sales prices:⁽²⁾
ATLAS GROWTH:
Natural gas (per Mcf)	$ 2.13		$ 3.45	$ 2.55	$ 4.00
Oil (per Bbl)⁽⁴⁾	$ 44.11		$ 71.75	$ 46.83	$ 88.61
Natural gas liquids (per Bbl)	$ 12.07		$ 22.11	$ 12.51	$ 28.80
ATLAS RESOURCE:
Natural gas (per Mcf)⁽³⁾	$ 3.42		$ 3.66	$ 3.41	$ 3.76
Oil (per Bbl)⁽⁴⁾	$ 85.26		$ 84.81	$ 84.30	$ 87.76
Natural gas liquids (per Bbl)⁽⁵⁾	$ 23.17		$ 26.97	$ 22.40	$ 29.59

Production costs per Mcfe:⁽²⁾⁽⁶⁾
ATLAS GROWTH:

Lease operating expenses per Mcfe	$ 0.51		$ 2.35	$ 0.83	$ 2.47
Production taxes per Mcfe	0.28		0.43	0.31	0.48
Transportation and compression expenses per Mcfe	0.10		0.02	0.07	0.00
Total production costs per Mcfe	$ 0.89		$ 2.79	$ 1.21	$ 2.95
ATLAS RESOURCE:
Lease operating expenses per Mcfe	$ 1.33		$ 1.32	$ 1.34	$ 1.27
Production taxes per Mcfe	0.17		0.28	0.19	0.27
Transportation and compression expenses per Mcfe	0.23		0.22	0.24	0.25
Total production costs per Mcfe	$ 1.73		$ 1.82	$ 1.76	$ 1.80
TOTAL:
Lease operating expenses per Mcfe	$ 1.31		$ 1.33	$ 1.33	$ 1.28
Production taxes per Mcfe	0.17		0.28	0.19	0.27
Transportation and compression expenses per Mcfe	0.23		0.22	0.23	0.25
Total production costs per Mcfe	$ 1.71		$ 1.83	$ 1.75	$ 1.81


⁽¹⁾ Production quantities consist of the sum of (i) the proportionate share of production from wells in which AGP 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.
⁽²⁾ "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.
⁽³⁾ ARP's average sales prices for natural gas before the effects of financial hedging were $1.96 per Mcf and $3.52 per Mcf for the three months ended December 31, 2015 and 2014, respectively, and $2.23 per Mcf and $3.93 per Mcf for the years ended December 31, 2015 and 2014, respectively. ARP's amounts exclude the impact of subordination of ARP's production revenues to investor partners within its investor partnerships. Including the effects of this subordination, ARP's average natural gas sales prices were $3.39 per Mcf ($1.93 per Mcf before the effects of financial hedging) and $3.61 per Mcf ($3.46 per Mcf before the effects of financial hedging) for the three months ended December 31, 2015 and 2014, respectively, and $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging) and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2015 and 2014, respectively.
⁽⁴⁾ AGP's average sales price for oil before the effects of financial hedging was $41.27 per barrel and $71.75 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $44.98 per barrel and $88.61 per barrel for the years ended December 31, 2015 and 2014, respectively. ARP's average sales prices for oil before the effects of financial hedging were $36.13 per barrel and $65.29 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $44.19 per barrel and $82.22 per barrel for the years ended December 31, 2015 and 2014, respectively.
⁽⁵⁾ ARP's average sales prices for natural gas liquids before the effects of financial hedging were $11.99 per barrel and $21.80 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $12.77 per barrel and $29.39 per barrel for the years ended December 31, 2015 and 2014, 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, ARP's lease operating expenses per Mcfe were $1.32 per Mcfe ($1.72 per Mcfe for total production costs) and $1.31 per Mcfe ($1.80 per Mcfe for total production costs) for the three months ended December 31, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.74 per Mcfe for total production costs) and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2015 and 2014, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.29 per Mcfe ($1.70 per Mcfe for total production costs) and $1.31 per Mcfe ($1.81 per Mcfe for total production costs) for the three months ended December 31, 2015 and 2014, respectively, and $1.31 per Mcfe ($1.73 per Mcfe for total production costs) and $1.26 per Mcfe ($1.78 per Mcfe for total production costs) for the years ended December 31, 2015 and 2014, respectively.

ATLAS ENERGY GROUP, LLC
Financial Information
(unaudited; in thousands except per unit amounts)

	Three Months Ended		Years Ended
	December 31,		December 31
Reconciliation of net loss to non-GAAP measures⁽¹⁾:	2015	2014	2015	2014
Net loss	$ (297,357)	$ (594,551)	$ (885,734)	$ (640,746)
Distributable cash flow not attributable to unitholders prior to February 27, 2015 (the asset transfer date)⁽²⁾	—	(15,823)	(4,291)	(58,738)
Atlas Resource net loss attributable to unitholders	62,926	153,157	177,410	151,831
Atlas Resource cash distributions earned by ATLS⁽³⁾	2,816	18,720	30,930	73,284
Atlas Growth net loss attributable to unitholders	6	352	237	837
Atlas Growth cash distributions earned by ATLS⁽³⁾	154	64	441	197
Non-recurring spinoff and acquisition costs	—	—	17,825	77
Amortization of deferred finance costs and predecessor Term Loan interest expense	761	329	16,785	1,270
Non-cash stock compensation expense	2,357	—	5,678	—
Gain on asset sales and disposal	—	(7)	—	(10)
Loss on extinguishment of debt	—	—	4,726	—
Preferred unit distributions	(1,014)	—	(3,360)	—
Other non-cash adjustments	369	148	2,105	559
Loss attributable to non-controlling interests	228,905	437,611	649,316	471,439
Distributable Cash Flow attributable to unitholders⁽¹⁾	$ (77)	$ —	$ 12,068	$ —

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Atlas Resource Cash Distributions Earned⁽³⁾:
Limited Partner Units	$ 2,699	$ 14,580	$ 28,871	$ 57,905
Series A Preferred Units (2%)	117	1,074	2,059	4,077
Incentive Distribution Rights	—	3,066	—	11,302
Total Atlas Resource Cash Distributions Earned⁽³⁾	2,816	18,720	30,930	73,284
per limited partner unit	$ 0.038	$ 0.590	$ 1.013	$ 2.343

Atlas Growth Cash Distributions Earned⁽³⁾	154	64	441	197

Total Cash Distributions Earned	2,970	18,784	31,371	73,481

Cash general and administrative expenses⁽⁴⁾	(1,444)	(1,146)	(9,406)	(6,909)
Other, net	1,066	701	4,494	2,187
Adjusted EBITDA⁽¹⁾	2,592	18,339	26,459	68,759
Cash interest expense⁽⁵⁾	(1,655)	(2,516)	(6,740)	(10,021)
Preferred unit distributions	(1,014)	—	(3,360)	—
Distributable Cash Flow⁽¹⁾	$ (77)	$ 15,823	$ 16,359	$ 58,738
Distributable cash flow not attributable to unitholders prior to February 27, 2015 (the asset transfer date)⁽²⁾	—	(15,823)	(4,291)	(58,738)
Distributable Cash Flow attributable to unitholders⁽¹⁾	$ (77)	$ —	$ 12,068	$ —

⁽¹⁾	EBITDA and Distributable Cash Flow is relevant and useful, because they help 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' 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; · Viability of potential acquisitions and other capital expenditure projects; and · Ability to comply with financial covenants in its debt 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 AGP 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⁾	In accordance with prevailing accounting literature, ATLS has adjusted its historical financial statements to present them combined with the historical financial results of the spin-off assets for all periods prior to its spin-off date of February 27, 2015.
⁽³⁾	Represents the cash distribution paid by ARP and AGP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.
⁽⁴⁾	Excludes non-cash stock compensation expense and certain non-recurring spinoff costs and acquisition and related costs.
⁽⁵⁾	Excludes non-cash amortization of deferred financing costs.

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ATLAS ENERGY GROUP, LLC
CAPITALIZATION INFORMATION
(unaudited; in thousands)

	December 31, 2015
	Atlas	Atlas
	Energy	Resource	Consolidated
Total debt	$ 72,700	$ 1,534,482	$ 1,607,182
Less: Cash	(29,861)	(1,353)	(31,214)
Total net debt	42,839	1,533,129	1,575,968

Unitholders' equity (deficit)	83,922	(84,628)	7,959⁽¹⁾

Total capitalization	$ 126,761	$ 1,448,501	$ 1,583,927

Ratio of net debt to capitalization	0.34x

⁽¹⁾Net of eliminated amounts.


	December 31, 2014
	Atlas	Atlas
	Energy	Resource	Consolidated
Total debt	$ 148,125	$1,394,460	$ 1,542,585
Less: Cash	(43,111)	(15,247)	(58,358)
Total net debt	105,014	1,379,213	1,484,227

Owner's equity	267,637	947,537	915,215⁽²⁾

Total capitalization	$ 372,651	$2,326,750	$ 2,399,442

Ratio of net debt to capitalization	0.28x

⁽²⁾Net of eliminated amounts.

ATLAS ENERGY GROUP, LLC
CONSOLIDATING STATEMENTS OF OPERATIONS
(unaudited; in thousands)
Three Months Ended December 31, 2015

	Atlas	Atlas
	Energy	Resource	Eliminations	Consolidated
Revenues:
Gas and oil production	$ 3,840	$ 64,756	$ −	$ 68,596
Well construction and completion	−	12,840	−	12,840
Gathering and processing	−	1,385	−	1,385
Administration and oversight	−	511	−	511
Well services	−	5,254	−	5,254
Gain on mark-to-market derivatives	102	57,517	−	57,619
Other, net	247	161	−	408
Total revenues	4,189	142,424	−	146,613

Costs and expenses:
Gas and oil production	545	39,429	−	39,974
Well construction and completion	−	11,165	−	11,165
Gathering and processing	−	2,207	−	2,207
Well services	−	2,427	−	2,427
General and administrative	5,964	21,568	−	27,532
Depreciation, depletion and amortization	3,856	32,030	−	35,886
Asset impairment	55	294,389	−	294,444
Total costs and expenses	10,420	403,215	−	413,635

Operating loss	(6,231)	(260,791)	−	(267,022)

Loss on asset sales and disposal	−	(905)	−	(905)
Interest expense	(2,402)	(27,028)	−	(29,430)

Net loss	(8,633)	(288,724)	−	(297,357)
Preferred unitholders' dividends	(1,014)	−	−	(1,014)
Loss attributable to non-controlling interests	−	−	228,905	228,905
Net loss attributable to unitholders	$ (9,647)	$ (288,724)	$ 228,905	$ (69,466)

ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATING STATEMENTS OF OPERATIONS
(unaudited; in thousands)
Three Months Ended December 31, 2014

	Atlas	Atlas
	Energy	Resource	Eliminations	Consolidated
Revenues:
Gas and oil production	$ 1,144	$ 132,158	$ −	$ 133,302
Well construction and completion	−	46,647	−	46,647
Gathering and processing	−	2,820	−	2,820
Administration and oversight	−	3,492	−	3,492
Well services	−	6,518	−	6,518
Gain on mark-to-market derivatives	−	2,819	−	2,819
Other, net	325	247	−	572
Total revenues	1,469	194,701	−	196,170

Costs and expenses:
Gas and oil production	518	49,188	−	49,706
Well construction and completion	−	40,562	−	40,562
Gathering and processing	−	3,625	−	3,625
Well services	−	2,482	−	2,482
General and administrative	5,534	21,455	−	26,989
Depreciation, depletion and amortization	720	63,846	−	64,566
Asset impairment	6,880	573,774	−	580,654
Total costs and expenses	13,652	754,932	−	768,584

Operating loss	(12,183)	(560,231)	−	(572,414)

Gain (loss) on asset sales and disposal	7	(183)	−	(176)
Interest expense	(2,845)	(19,116)	−	(21,961)

Net loss	(15,021)	(579,530)	−	(594,551)
Loss attributable to non-controlling interests	−	−	437,611	437,611
Net loss attributable to owner	$ (15,021)	$ (579,530)	$ 437,611	$ (156,940)

ATLAS ENERGY GROUP, LLC
COMBINED CONDENSED CONSOLIDATING BALANCE SHEETS
(unaudited; in thousands)
December 31, 2015

	Atlas	Atlas
ASSETS	Energy	Resource	Eliminations	Consolidated
Current assets:
Cash and cash equivalents	$ 29,861	$ 1,353	$ −	$ 31,214
Accounts receivable	3,492	63,367	(939)	65,920
Receivable from (advances to) affiliates	9,924	(9,924)	−	−
Current portion of derivative asset	303	159,460	−	159,763
Subscriptions receivable	−	19,877	−	19,877
Prepaid expenses and other	62	22,935	−	22,997
Total current assets	43,642	257,068	(939)	299,771

Property, plant and equipment, net	125,286	1,191,611	−	1,316,897
Intangible assets, net	−	456	−	456
Goodwill, net	−	13,639	−	13,639
Long-term derivative asset	109	198,262	−	198,371
Investment in subsidiaries	(7,726)	−	7,726	−
Other assets, net	27,997	60,044	939	88,980
	$ 189,308	$ 1,721,080	$ 7,726	$ 1,918,114

LIABILITIES AND UNITHOLDERS' EQUITY (DEFICIT)

Current liabilities:
Accounts payable	$ 3,301	$ 49,249	$ −	$ 52,550
Liabilities associated with drilling contracts	−	21,483	−	21,483
Accrued interest	16	25,436	−	25,452
Accrued well drilling and completion costs	6,641	26,914	−	33,555
Accrued liabilities	16,959	28,994	(939)	45,014
Total current liabilities	26,917	152,076	(939)	178,054

Long-term debt, less current portion	72,700	1,534,482	−	1,607,182
Asset retirement obligations and other	5,769	119,150	−	124,919

Unitholders' equity (deficit):
Common unitholders' deficit	(99,788)	−	−	(99,788)
Series A preferred equity	37,515	−	−	37,515
Partners' deficit	−	(104,003)	104,003	−
Accumulated other comprehensive income	4,284	19,375	(19,375)	4,284
	(57,989)	(84,628)	84,628	(57,989)
Non-controlling interests	141,911	−	(75,963)	65,948
Total unitholders' equity (deficit)	83,922	(84,628)	8,665	7,959
	$ 189,308	$ 1,721,080	$ 7,726	$ 1,918,114

ATLAS ENERGY GROUP, LLC
Ownership Interests Summary

Atlas Energy Ownership Interests as of February 25, 2016:	Amount	Overall Ownership Interest Percentage

ATLAS RESOURCE:
General partner interest	100%	2.0%
Common units	20,962,485	19.7%
Preferred units	3,749,986	3.5%
Incentive distribution rights	100%	N/A
Total Atlas Energy ownership interests in Atlas Resource		25.2%

ATLAS GROWTH:
General partner interest	80.0%	2.0%
Common units	500,010	2.1%
Incentive distribution rights	80.0%	N/A
Total Atlas Energy ownership interests in Atlas Growth		4.1%

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

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,
	2015	2014	2015	2014
Revenues:
Gas and oil production	$ 64,756	$ 132,158	$ 356,999	$ 470,051
Well construction and completion	12,840	46,647	76,505	173,564
Gathering and processing	1,385	2,820	7,431	14,107
Administration and oversight	511	3,492	7,812	15,564
Well services	5,254	6,518	23,822	24,959
Gain on mark-to-market derivatives	57,517	2,819	267,223	2,819
Other, net	161	247	241	590
Total revenues	142,424	194,701	740,033	701,654

Costs and expenses:
Gas and oil production	39,429	49,188	169,653	182,226
Well construction and completion	11,165	40,562	66,526	150,925
Gathering and processing	2,207	3,625	9,613	15,525
Well services	2,427	2,482	9,162	10,007
General and administrative	21,568	21,455	65,968	72,349
Depreciation, depletion and amortization	32,030	63,846	157,978	239,923
Asset impairment	294,389	573,774	966,635	573,774
Total costs and expenses	403,215	754,932	1,445,535	1,244,729

Operating loss	(260,791)	(560,231)	(705,502)	(543,075)

Loss on asset sales and disposal	(905)	(183)	(1,181)	(1,869)
Interest expense	(27,028)	(19,116)	(102,133)	(62,144)

Net loss	(288,724)	(579,530)	(808,816)	(607,088)

Preferred limited partner dividends	(4,289)	(5,969)	(16,469)	(19,267)
Net loss attributable to common limited partners and the general partner	$ (293,013)	$ (585,499)	$ (825,285)	$ (626,355)

Allocation of net loss attributable to common limited partners and the general partner:
General partner's interest	$ (5,860)	$ (8,649)	$ (16,505)	$ (1,222)
Common limited partners' interest	(287,153)	(576,850)	(808,780)	(625,133)
Net loss attributable to common limited partners and the general partner	$ (293,013)	$ (585,499)	$ (825,285)	$ (626,355)

Net loss attributable to common limited partners per unit:
Basic	$ (2.81)	$ (7.04)	$ (8.63)	$ (8.37)
Diluted	$ (2.81)	$ (7.04)	$ (8.63)	$ (8.37)

Weighted average common limited partner units outstanding:
Basic	102,061	81,919	93,745	74,716
Diluted	102,061	81,919	93,745	74,716

ATLAS RESOURCE PARTNERS, L.P. Financial and Operating Highlights (unaudited)

	Three Months Ended		Years Ended
	December 31,		December 31,
	2015	2014	2015	2014

Net loss attributable to common limited partners per unit - basic	$ (2.81)	$ (7.04)	$ (8.63)	$ (8.37)

Cash distributions paid per unit⁽¹⁾	$ 0.038	$ 0.590	$ 1.013	$ 2.343

Production revenues (in thousands):
Natural gas	$ 36,228	$ 79,687	$ 217,236	$ 318,920
Oil	25,173	42,444	122,273	110,070
Natural gas liquids	3,355	10,027	17,490	41,061
Total production revenues	$ 64,756	$ 132,158	$ 356,999	$ 470,051

Production volume:⁽²⁾⁽³⁾
Appalachia:⁽⁴⁾
Natural gas (Mcfd)	30,173	35,420	31,930	38,160
Oil (Bpd)	312	355	335	381
Natural gas liquids (Bpd)	31	43	33	41
Total (Mcfed)	32,230	37,807	34,139	40,689
Coal-bed Methane:⁽⁴⁾
Natural gas (Mcfd)	123,928	137,943	129,453	132,296
Oil (Bpd)	—	—	—	—
Natural gas liquids (Bpd)	—	—	—	—
Total (Mcfed)	123,928	137,943	129,453	132,296
Barnett/Marble Falls:
Natural gas (Mcfd)	40,327	54,143	45,220	57,361
Oil (Bpd)	383	923	564	1,066
Natural gas liquids (Bpd)	1,709	2,598	1,992	2,698
Total (Mcfed)	52,874	75,264	60,555	79,946
Rangely/Eagle Ford: ⁽⁴⁾⁽⁵⁾
Natural gas (Mcfd)	250	693	315	175
Oil (Bpd)	3,902	3,535	3,818	1,538
Natural gas liquids (Bpd)	308	421	320	173
Total (Mcfed)	25,513	24,433	25,147	10,438
Mississippi Lime/Hunton:
Natural gas (Mcfd)	5,529	8,339	6,570	6,810
Oil (Bpd)	289	599	404	427
Natural gas liquids (Bpd)	467	669	546	561
Total (Mcfed)	10,059	15,948	12,269	12,734
Other Operating Areas:⁽⁴⁾
Natural gas (Mcfd)	2,914	3,152	3,126	3,253
Oil (Bpd)	13	27	17	25
Natural gas liquids (Bpd)	309	310	263	330
Total (Mcfed)	4,845	5,177	4,811	5,384
Total Production:
Natural gas (Mcfd)	203,121	239,690	216,613	238,054
Oil (Bpd)	4,898	5,440	5,139	3,436
Natural gas liquids (Bpd)	2,824	4,040	3,155	3,802
Total (Mcfed)	249,450	296,571	266,374	281,486

Average sales prices:⁽³⁾
Natural gas (per Mcf)⁽⁶⁾	$ 3.42	$ 3.66	$ 3.41	$ 3.76
Oil (per Bbl)⁽⁷⁾	$ 85.26	$ 84.81	$ 84.30	$ 87.76
Natural gas liquids (per Bbl)⁽⁸⁾	$ 23.17	$ 26.97	$ 22.40	$ 29.59

Production costs:⁽³⁾⁽⁹⁾	$ 1.33	$ 1.32	$ 1.34	$ 1.27
Lease operating expenses per Mcfe	0.17	0.28	0.19	0.27
Production taxes per Mcfe	0.23	0.22	0.24	0.25
Transportation and compression expenses per Mcfe	$ 1.73	$ 1.82	$ 1.76	$ 1.80
Total production costs per Mcfe

Depletion per Mcfe⁽³⁾	$ 1.25	$ 2.23	$ 1.49	$ 2.23

⁽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 Arkoma Basin in eastern Oklahoma; 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 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 $1.96 per Mcf and $3.52 per Mcf for the three months ended December 31, 2015 and 2014, respectively, and $2.23 per Mcf and $3.93 per Mcf for the years ended December 31, 2015 and 2014, 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 $3.39 per Mcf ($1.93 per Mcf before the effects of financial hedging) and $3.61 per Mcf ($3.46 per Mcf before the effects of financial hedging) for the three months ended December 31, 2015 and 2014, respectively, and $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging) and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2015 and 2014, respectively.

⁽⁷⁾	ARP's average sales prices for oil before the effects of financial hedging were $36.13 per barrel and $65.29 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $44.19 per barrel and $82.22 per barrel for the years ended December 31, 2015 and 2014, respectively.

⁽⁸⁾	ARP's average sales prices for natural gas liquids before the effects of financial hedging were $11.99 per barrel and $21.80 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $12.77 per barrel and $29.39 per barrel for the years ended December 31, 2015 and 2014, 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 ($1.72 per Mcfe for total production costs) and $1.31 per Mcfe ($1.80 per Mcfe for total production costs) for the three months ended December 31, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.74 per Mcfe for total production costs) and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2015 and 2014, respectively.

ATLAS RESOURCE PARTNERS, L.P. CAPITALIZATION INFORMATION (unaudited; in thousands)

	December 31, 2015	December 31, 2014
Total debt	$ 1,534,482	$ 1,394,460
Less: Cash	(1,353)	(15,247)
Total net debt/(cash)	1,533,129	1,379,213

Partners' capital (deficit)	(84,628)	947,537

Total capitalization	$ 1,448,501	$ 2,326,750

Ratio of net debt to capitalization	1.06x	0.59x

ATLAS RESOURCE PARTNERS, L.P CAPITAL EXPENDITURE DATA (unaudited; in thousands)

	Three Months Ended		Years Ended
	December 31,		December 31,
	2015	2014	2015	2014
Maintenance capital expenditures ⁽¹⁾	$ 11,000	$ 19,000	$ 53,788	$ 65,300
Expansion capital expenditures	13,848	43,149	73,350	147,428
Total	$ 24,848	$ 62,149	$ 127,138	$ 212,728

	ATLAS RESOURCE PARTNERS, L.P. Hedge Position Summary (as of February 25, 2016)

Natural Gas

	Fixed Price Swaps
		Average
	Production Period	Fixed Price	Volumes
	Ended December 31,	(per mmbtu)^(a)	(mmbtus)^(a)

	2016^(b)	$ 4.23	53,546,300
	2017	$ 4.22	49,920,000
	2018	$ 4.17	40,800,000
	2019	$ 4.02	15,960,000

	Put Options – Drilling Partnerships
		Average	Average
	Production Period	Fixed Price	Volumes
	Ended December 31,	(per mmbtu)^(a)	(mmbtus)^(a)

	2016^(b)	$ 4.15	1,440,000

Crude Oil

	Fixed Price Swaps
		Average
	Production Period	Fixed Price	Volumes
	Ended December 31,	(per bbl)^(a)	(bbls)^(a)

	2016^(b)	$ 81.47	1,557,000
	2017	$ 77.28	1,140,000
	2018	$ 76.28	1,080,000
	2019	$ 68.37	540,000
Natural Gas Liquids

	Crude Fixed Price Swaps
		Average
	Production Period	Fixed Price	Volumes
	Ended December 31,	(per bbl)^(a)	(bbls)^(a)

	2016^(b)	$ 85.65	84,000

^(a)	"mmbtu" represents million metric British thermal units; "bbl" represents barrel.
^(b)	Reflects hedges covering the full twelve months of 2016.


⁽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 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 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 the Eagle Ford Shale, 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⁾	Includes cash settlements on commodity derivative contracts not previously recorded within accumulated other comprehensive income following the de-designation of hedges on January 1, 2015.
⁽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.
⁽⁷⁾	Including the discretionary adjustments by the Board of Directors of ARP's General Partner in the determination of quarterly cash distributions, Adjusted EBITDA would have been $89.6 million for the three months ended December 31, 2014 and $348.3 million for the year ended December 31, 2014, respectively.
⁽⁸⁾	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.
⁽⁹⁾	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.