(1)

A reconciliation of GAAP net income (loss) to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 61 to the Financial Information table of this release.

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

 (unaudited; in thousands)

December 31,

December 31,

ASSETS

2015

2014

Current assets:

      Cash and cash equivalents

$               1,353

$             15,247

      Accounts receivable

63,367

114,520

      Advances to affiliates

—

6,567

      Current portion of derivative asset

159,460

144,259

      Subscriptions receivable

19,877

32,398

      Prepaid expenses and other

22,935

26,296

          Total current assets

266,992

339,287

Property, plant and equipment, net

1,191,611

2,263,820

Goodwill and intangible assets, net

14,095

14,330

Long-term derivative asset

198,262

130,602

Other assets, net

60,044

50,081

$        1,731,004

$        2,798,120

LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)

Current liabilities:

      Accounts payable

$             49,249

$           111,198

      Advances from affiliates

9,924

8,816

      Liabilities associated with drilling contracts

21,483

40,611

      Accrued well drilling and completion costs

26,914

80,404

      Distribution payable

4,334

20,876

      Accrued liabilities

50,096

84,235

          Total current liabilities

162,000

346,140

Long-term debt

1,534,482

1,394,460

Asset retirement obligations and other

119,150

109,983

Commitments and contingencies

Partners' Capital (Deficit):

      General partner's interest

(33,642)

(13,697)

      Preferred limited partners' interests

188,739

163,522

      Common limited partners' interests

(260,276)

605,065

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

19,375

191,471

Total partners' capital (deficit)

(84,628)

947,537

$         1,731,004

$         2,798,120

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

(1)

Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its Distributable Cash Flow and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including 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.

ATLAS RESOURCE PARTNERS, L.P.

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

$     (288,724)

$     (579,530)

$     (808,816)

$     (607,088)

Acquisition and related costs

5,562

5,049

10,597

17,814

Depreciation, depletion and amortization

32,030

63,846

157,978

239,923

Asset impairment

294,389

573,774

966,635

573,774

Amortization of deferred finance costs

5,240

3,155

19,638

9,445

Non-cash stock compensation expense

447

1,725

4,945

8,067

Maintenance capital expenditures(2)

(11,000)

(16,300)

(53,788)

(50,550)

Preferred unit distributions

(4,291)

(4,707)

(16,904)

(18,005)

Loss on asset sales and disposal

905

183

1,181

1,869

Non-cash valuation allowance

–

1,590

–

1,590

Cash settlements on commodity derivative contracts(3)

43,779

–

94,186

–

Unrealized gain on mark-to-market derivatives

(57,517)

(2,819)

(267,223)

(2,819)

Other

(132)

(188)

(110)

(204)

Distributable cash flow attributable to limited partners and the general partner(1)

$        20,688

$        45,778

$      108,319

$      173,816

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$        69,106

$        82,970

$      281,532

$      287,825

Well construction and completion margin

1,675

6,085

9,979

22,639

Administration and oversight margin

511

3,492

7,812

15,564

Well services margin

2,827

4,036

14,660

14,952

Gathering and processing margin

(822)

(805)

(2,182)

(1,418)

Cash general and administrative expenses(4)

(15,559)

(13,091)

(50,426)

(44,878)

Other, net

29

59

131

386

Adjusted EBITDA(1)

57,767

82,746

261,506

295,070

Cash interest expense(5)

(21,788)

(15,961)

(82,495)

(52,699)

Preferred unit distributions

(4,291)

(4,707)

(16,904)

(18,005)

Maintenance capital expenditures(2)

(11,000)

(16,300)

(53,788)

(50,550)

Distributable Cash Flow attributable to limited partners and the general partner(1)

$        20,688

$        45,778

$      108,319

$      173,816

Discretionary adjustments considered by the Board of Directors of the General Partner in the determination of quarterly cash distributions:

Net cash from acquisitions from the effective date through closing date(6)

−

3,757

−

33,959

Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7)

$        20,688

$        49,535

$      108,319

$      207,775

Distributions Paid(8)

$          3,948

$        53,729

$        95,278

$      198,740

  per limited partner unit

$          0.038

$          0.590

$          1.013

$          2.343

Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(9)

$        16,740

$         (4,194)

$        13,041

$          9,035

(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.

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

2017

$    83.78

60,000

(a)

"mmbtu" represents million metric British thermal units; "bbl" represents barrel.

(b)

Reflects hedges covering the full twelve months of 2016.