Atlas Resource Partners, L.P. Reports Operating and Financial Results for the Second Quarter 2014

⁽¹⁾

ARP's net daily production for the second quarter 2014 includes 50 days of production from the natural gas assets acquired from GeoMet in West Virginia; second quarter net daily natural gas production would have been approximately 235.9 Mmcfd (compared to the reported 226.7 MMcfd) inclusive of a full quarter of the West Virginia assets;  the acquired oil and liquids production in the Rangely Field in Colorado is not included in second quarter 2014 production amounts

⁽²⁾

A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 7 to the Financial Information table of this release.

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except per unit data)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

Revenues:

     Gas and oil production

$      104,057

$        47,094

$      200,302

$        93,158

     Well construction and completion

16,336

24,851

65,713

81,329

     Gathering and processing

3,758

4,463

8,226

8,048

     Administration and oversight

4,166

3,391

5,895

4,476

     Well services

6,365

4,864

11,844

9,680

Other, net

35

(1,337)

82

(1,317)

          Total revenues

134,717

83,326

292,062

195,374

Costs and expenses:

     Gas and oil production

41,763

19,035

78,555

34,251

     Well construction and completion

14,206

21,609

57,142

70,721

     Gathering and processing

4,273

4,959

8,686

9,372

     Well services     

2,426

2,305

4,908

4,623

     General and administrative

21,315

14,217

37,770

31,784

Depreciation, depletion and amortization

58,001

22,197

108,238

43,405

          Total costs and expenses     

141,984

84,322

295,299

194,156

Operating income (loss)

(7,267)

(996)

(3,237)

1,218

Gain (loss) on asset sales and disposal

9

(672)

(1,594)

(1,374)

Interest expense

(13,263)

(4,508)

(26,451)

(11,397)

Net loss

(20,521)

(6,176)

(31,282)

(11,553)

Preferred limited partner dividends

(4,424)

(2,071)

(8,823)

(4,028)

Net loss attributable to common limited partners and the general partner

$       (24,945)

$       (8,247)

$       (40,105)

Allocation of net loss attributable to common limited partners and the general partner:

General partner's interest

$          2,377

$        1,022

$          4,381

$          1,323

Common limited partners' interest

(27,322)

(9,269)

(44,486)

(16,904)

Net loss attributable to common limited partners and the general partner

$      (24,945)

$      (8,247)

$      (40,105)

$      (15,581)

Net loss attributable to common limited partners per unit:

Basic and Diluted

$          (0.37)

$         (0.20)

$          (0.66)

$         (0.37)

Weighted average common limited partner units outstanding:

Basic and Diluted

73,900

47,007

67,595

45,499

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

June 30,

December 31,

ASSETS

2014

2013

Current assets:

      Cash and cash equivalents

$               3,993

$               1,828

      Accounts receivable

85,419

58,822

      Current portion of derivative asset

255

1,891

      Subscriptions receivable

16,336

47,692

      Prepaid expenses and other

21,023

10,097

          Total current assets

127,026

120,330

Property, plant and equipment, net

2,666,718

2,120,818

Goodwill and intangible assets, net

32,611

32,747

Long-term derivative asset

3,415

27,084

Other assets, net

51,516

42,821

$        2,881,286

$        2,343,800

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable

$             96,778

$             69,346

      Advances from affiliates

27,838

26,742

      Liabilities associated with drilling contracts

—

49,377

      Current portion of derivative liability

19,983

6,353

      Accrued well drilling and completion costs

70,319

40,481

      Distribution payable

18,497

—

      Accrued liabilities

40,816

51,416

          Total current liabilities

274,231

243,715

Long-term debt

1,203,973

942,334

Asset retirement obligations and other

102,606

90,460

Commitments and contingencies

Partners' Capital:

      General partner's interest

249

4,482

      Preferred limited partners' interests

180,566

183,477

      Common limited partners' interests

1,132,694

852,457

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income (loss)

(14,209)

25,699

Total partners' capital

1,300,476

1,067,291

$         2,881,286

$         2,343,800

ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

Net loss attributable to common limited partners per unit - basic

$         (0.37)

$            (0.20)

$         (0.66)

$           (0.37)

Cash distributions paid per unit⁽¹⁾

$          0.583

$           0.540

$           1.163

$           1.050

Production revenues (in thousands):

Natural gas 

$       77,600

$        28,383

$     151,790

$        57,439

Oil

17,192

10,595

29,475

19,401

Natural gas liquids

9,265

8,116

19,037

16,318

Total production revenues

$     104,057

$        47,094

$     200,302

$        93,158

Production volume:⁽²⁾⁽³⁾

Appalachia: ⁽⁴⁾

Natural gas (Mcfd)

37,916

30,715

39,522

31,139

Oil (Bpd)

388

283

401

280

Natural gas liquids (Bpd)

45

2

37

2

Total (Mcfed)

40,513

32,421

42,152

32,830

Coal-bed Methane^{: (4)}

Natural gas (Mcfd)

119,465

—

113,948

—

Oil (Bpd)

—

—

—

—

Natural gas liquids (Bpd)

—

—

—

—

Total (Mcfed)

119,465

—

113,948

—

Barnett/Marble Falls^:

Natural gas (Mcfd)

59,711

66,407

58,810

66,239

Oil (Bpd)

1,231

863

1,034

821

Natural gas liquids (Bpd)

2,762

2,748

2,666

2,653

Total (Mcfed)

83,669

88,070

81,009

87,086

Mississippi Lime/Hunton: 

Natural gas (Mcfd)

6,325

3,978

6,100

4,365

Oil (Bpd)

437

115

369

72

Natural gas liquids (Bpd)

543

245

514

244

Total (Mcfed)

12,205

6,138

11,400

6,265

Other Operating Areas:⁽⁴⁾

Natural gas (Mcfd)

3,267

4,538

3,334

4,699

Oil (Bpd)

27

20

23

17

Natural gas liquids (Bpd)

340

392

339

393

Total (Mcfed)

5,470

7,012

5,506

7,161

Total Production:⁽³⁾

Natural gas (Mcfd)

226,684

105,638

221,714

106,442

Oil (Bpd)

2,084

1,281

1,827

1,191

Natural gas liquids (Bpd)

3,689

3,386

3,556

3,292

Total (Mcfed)

261,323

133,641

254,016

133,341

Average sales prices: ⁽³⁾

Natural gas (per Mcf) ⁽⁵⁾

$           3.78

$           3.31

$           3.92

$           3.32

Oil (per Bbl)⁽⁶⁾

$         90.66

$         90.90

$         89.12

$         89.97

Natural gas liquids (per Bbl) ⁽⁷⁾

$         27.60

$         26.34

$         29.57

$         27.39

Production costs:⁽³⁾⁽⁸⁾

        Lease operating expenses per Mcfe

$           1.24

$           1.21

$           1.21

$           1.09

Production taxes per Mcfe

0.24

0.23

0.26

0.23

Transportation and compression expenses per Mcfe

0.27

0.24

0.28

0.20

Total production costs per Mcfe

$           1.76

$           1.68

$           1.74

$           1.51

Depletion per Mcfe⁽³⁾

$           2.34

$           1.69

$           2.25

$           1.67

⁽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; Raton/Black Warrior includes ARP's production located in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama; Other operating areas include ARP's production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

⁽⁵⁾  

ARP's average sales prices for natural gas before the effects of financial hedging were $4.13 per Mcf and $3.47 per Mcf for the three months ended June 30, 2014 and 2013, respectively, and $4.40 per Mcf and $3.18 per Mcf for the six months ended June 30, 2014 and 2013, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships.  Including the effects of subordination, average natural gas sales prices were $3.76 per Mcf ($4.11 per Mcf before the effects of financial hedging) and $2.95 per Mcf ($3.10 per Mcf before the effects of financial hedging) for the three months ended June 30, 2014 and 2013, respectively, and $3.78 per Mcf ($4.26 per Mcf before the effects of financial hedging) and $2.98 per Mcf ($2.85 per Mcf before the effects of financial hedging) for the six months ended June 30, 2014 and 2013, respectively.

⁽⁶⁾    

ARP's average sales prices for oil before the effects of financial hedging were $98.95 per barrel and $92.33 per barrel for the three months ended June 30, 2014 and 2013, respectively, and $96.49 per barrel and $91.63 per barrel for the six months ended June 30, 2014 and 2013, respectively.

⁽⁷⁾   

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $28.93 per barrel and $26.54 per barrel for the three months ended June 30, 2014 and 2013, respectively, and $32.15 per barrel and $27.60 per barrel for the six months ended June 30, 2014 and 2013, respectively.

 ⁽⁸⁾ 

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 $1.24 per Mcfe ($1.76 per Mcfe for total production costs) and $1.10 per Mcfe ($1.57 per Mcfe for total production costs) for the three months ended June 30, 2014 and 2013, respectively, and $1.17 per Mcfe ($1.71 per Mcfe for total production costs) and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) for the six months ended June 30, 2014 and 2013, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)

June 30,

2014

December 31,

2013

Total debt

$     1,203,973

$         942,334

Less:  Cash

(3,993)

(1,828)

Total net debt/(cash)

1,199,980

940,506

Partners' capital  

1,300,476

1,067,291

Total capitalization

$     2,500,456

$     2,007,797

Ratio of net debt to capitalization

0.48x

0.47x

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

Maintenance capital expenditures⁽¹⁾

$    13,100

$      7,000

$    23,900

$    11,000

Expansion capital expenditures

41,558

64,565

70,655

119,052

        Total

$    54,658

$    71,565

$    94,555

$  130,052

⁽¹⁾

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

ATLAS RESOURCE PARTNERS, L.P.

Financial Information

(unaudited; in thousands, except per unit amounts)

Three Months Ended

Six Months Ended

June 30,

June 30,

Reconciliation of net loss to non-GAAP measures⁽¹⁾:

2014

2013

2014

2013

Net loss

$       (20,521)

$         (6,176)

$       (31,282)

$       (11,553)

Acquisition and related costs

8,791

2,766

11,170

6,480

Depreciation, depletion and amortization

58,001

22,197

108,238

43,405

Amortization of deferred finance costs

2,042

1,153

3,854

5,795

Non-cash stock compensation expense

2,009

3,002

4,354

7,249

Maintenance capital expenditures⁽²⁾

(10,650)

(4,500)

(21,150)

(8,500)

Loss (gain) on asset sales and disposal

(9)

672

1,594

1,374

Premiums paid on swaption derivative contracts associated with asset acquisitions⁽³⁾

−

1,309

−

1,309

Other

5

−

2

−

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

$        39,668

$        20,423

$        76,780

$        45,559

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$        62,294

$        28,059

$      121,747

$        58,907

Well construction and completion margin

2,130

3,242

8,571

10,608

Administration and oversight margin

4,166

3,391

5,895

4,476

Well services margin

3,939

2,559

6,936

5,057

Gathering and processing margin

(515)

(496)

(460)

(1,324)

Cash general and administrative expenses⁽⁴⁾

(10,515)

(8,449)

(22,246)

(18,055)

Other, net

40

(28)

84

(8)

Adjusted EBITDA⁽¹⁾

61,539

28,278

120,527

59,661

Cash interest expense⁽⁵⁾

(11,221)

(3,355)

(22,597)

(5,602)

Maintenance capital expenditures⁽²⁾

(10,650)

(4,500)

(21,150)

(8,500)

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

$        39,668

$        20,423

$        76,780

$        45,559

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⁾

14,791

20,547

19,988

20,547

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

$        54,459

$        40,970

$        96,768

$        66,106

Distributions Paid⁽⁸⁾

$        55,893

$        36,053

$      101,624

$        61,384

  per limited partner unit

$          0.583

$          0.540

$          1.163

$          1.050

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

$         (1,434)

$          4,917

$         (4,856)

$          4,722

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

⁽⁵⁾

Excludes non-cash amortization of deferred financing costs.

⁽⁶⁾

These amounts reflect net cash proceeds received from the respective effective date through the respective closing date of assets acquired, less estimated and pro forma amounts of maintenance capital expenditures and financing costs.  The management of ARP believes these amounts are critical in its evaluation of DCF and cash distributions for the period.  Under GAAP, such amounts are characterized as purchase price adjustments and are reflected in the net purchase price paid for the acquired assets, rather than reflected as components of net income or loss for the period.  For the 2^nd quarter 2014, such amounts include net cash generated by the GeoMet assets from April 1, 2014 to May 11, 2014, and the Rangely assets from April 1, 2014 to June 30, 2014 of $17.6 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.4 million. For the 2^nd quarter 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to June 30, 2013 of $25.5 million, less pro forma interest expense of $2.5 million and estimated maintenance capital expenditures of $2.5 million. For the six months ended June 30, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to May 11, 2014, and the Rangely assets from April 1, 2014 to June 30, 2014 of $23.1 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.7 million.  For the six months ended June 30, 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to June 30, 2013 of $25.5 million, less pro forma interest expense of $2.5 million and estimated maintenance capital expenditures of $2.5 million.    

⁽⁷⁾

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 $79.2 million and $53.8 million for the three months ended June 30, 2014 and 2013, respectively, and $143.7 million and $85.2 million for the six months ended June 30, 2014 and 2013, 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.  The Partnership's determination of quarterly cash distributions and its resulting determination of the amount of excess (shortfall) those cash distributions generate in comparison to Distributable Cash Flow are based upon its assessment of numerous factors, including but not limited to future commodity price and interest rate movements, variability of well productivity, weather effects, and financial leverage.  ARP also considers its historical trailing four quarters of excess or shortfalls and future forecasted excess or shortfalls that its cash distributions generate in comparison to Distributable Cash Flow due to the variability of its Distributable Cash Flow generated each quarter, which could cause it to have more or less excess (shortfalls) generated from quarter to quarter.  

ATLAS RESOURCE PARTNERS, L.P.

Hedge Position Summary

(as of August 7, 2014)

Natural Gas

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    4.15

30,076,488

2015

$    4.24

51,924,492

2016

$    4.31

45,746,320

2017

$    4.53

24,840,000

2018

$    4.62

9,360,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    4.22

$    5.12

1,920,000

2015

$    4.23

$    5.13

3,480,000

Put Options – Drilling Partnerships

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    3.80

900,000

2015

$    4.00

1,440,000

2016

$    4.15

1,440,000

WAHA Basis Swaps

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    (0.1100)

5,400,000

NGPL Basis Swaps

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

   2014^(b)

$    (0.1082)

4,200,000

Natural Gas Liquids

Crude Oil Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

2016

$    85.65

84,000

2017

$    83.78

60,000

Mt Belvieu Ethane Purity Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    0.3025

30,000

Mt Belvieu Propane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    0.9996

147,000

2015

$    1.0161

192,000

Mt Belvieu Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    1.3075

18,000

2015

$    1.2481

36,000

Mt Belvieu Iso-Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    1.3225

18,000

2015

$    1.2631

36,000

Mt Belvieu Natural Gasoline Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

   2014^(b)

$    2.1225

55,000

2015

$    1.9831

120,000

Crude Oil

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

   2014^(b)

$    95.83

651,000

2015

$    90.85

1,443,000

2016

$    88.65

1,029,000

2017

$    87.75

492,000

2018

$    88.28

360,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

Ended December 31,

(per bbl)^(a)

(per bbl)^(a)

(bbls)^(a)

   2014^(b)

$    84.17

$  113.31

20,580

2015

$    83.85

$  110.65

29,250

^(a)

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

^(b)

Reflects hedges covering the last six months of 2014.

CONTACT:

Brian J. Begley

Vice President - Investor Relations

Atlas Resource Partners, L.P.

(877) 280-2857

(215) 405-2718 (fax)