Atlas Resource Partners, L.P. Reports Operating And Financial Results For The Third Quarter 2015

⁽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 STATEMENTS OF OPERATIONS

 (unaudited; in thousands, except per unit data)

Three Months Ended

Nine Months Ended

September 30,

September 30

2015

2014

2015

2014

Revenues:

      Gas and oil production

$        90,734

$      129,399

$      292,243

$    337,893

      Well construction and completion

23,054

61,204

63,665

126,917

      Gathering and processing

1,685

3,061

6,046

11,287

      Administration and oversight

5,495

6,177

7,301

12,072

      Well services

5,842

6,597

18,568

18,441

      Gain on mark-to-market derivatives

131,065

—

209,706

—

Other, net

20

261

80

343

          Total revenues

257,895

206,699

597,609

506,953

Costs and expenses:

      Gas and oil production

41,591

51,391

130,224

133,038

      Well construction and completion

20,046

53,221

55,361

110,363

      Gathering and processing

2,473

3,214

7,406

11,900

      Well services

2,398

2,617

6,735

7,525

      General and administrative

13,978

13,124

44,400

50,894

Depreciation, depletion and amortization

40,463

64,578

125,948

176,077

Asset impairment

672,246

—

672,246

—

          Total costs and expenses

793,195

188,145

1,042,320

489,797

Operating income (loss)

(535,300)

18,554

(444,711)

17,156

Loss on asset sales and disposal

(362)

(92)

(276)

(1,686)

Interest expense

(25,192)

(16,577)

(75,105)

(43,028)

Net income (loss)

(560,854)

1,885

(520,092)

(27,558)

Preferred limited partner dividends

(4,293)

(4,475)

(12,180)

(13,298)

Net loss attributable to common limited partners and the general partner

$     (565,147)

$       (2,590)

$     (532,272)

$    (40,856)

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

General partner's interest

$      (11,303)

$       3,009

$      (10,645)

$        7,427

Common limited partners' interest

(553,844)

(5,599)

(521,627)

(48,283)

Net loss attributable to common limited partners and the general partner

$ (565,147)

$      (2,590)

$     (532,272)

$    (40,856)

Net loss attributable to common limited partners per unit:

Basic

$          (5.73)

$         (0.07)

$         (5.74)

$        (0.67)

Diluted

$          (5.73)

$         (0.07)

$         (5.74)

$        (0.67)

Weighted average common limited partner units outstanding:

Basic

96,660

81,521

90,943

72,288

Diluted

96,660

81,521

90,943

72,288

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

September 30,

December 31,

ASSETS

2015

2014

Current assets:

      Cash and cash equivalents

$               2,418

$             15,247

      Accounts receivable

89,402

114,520

      Advances to affiliates

1,178

—

      Current portion of derivative asset

146,622

144,259

      Subscriptions receivable

23,054

32,398

      Prepaid expenses and other

25,407

26,296

          Total current assets

288,081

332,720

Property, plant and equipment, net

1,534,718

2,263,820

Goodwill and intangible assets, net

14,154

14,330

Long-term derivative asset

205,979

130,602

Other assets, net

53,826

50,081

$        2,096,758

$        2,791,553

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable

$             82,209

$           111,198

      Advances from affiliates

—

2,249

      Liabilities associated with drilling contracts

—

40,611

      Accrued well drilling and completion costs

56,300

80,404

      Distribution payable

14,234

20,876

      Accrued liabilities

77,002

84,235

          Total current liabilities

229,745

339,573

Long-term debt

1,505,047

1,394,460

Asset retirement obligations and other

117,089

109,983

Commitments and contingencies

Partners' Capital:

      General partner's interest

(27,465)

(13,697)

      Preferred limited partners' interests

188,910

163,522

      Common limited partners' interests

35,854

605,065

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

46,402

191,471

Total partners' capital

244,877

947,537

$         2,096,758

$         2,791,553

ATLAS RESOURCE PARTNERS, L.P

Financial and Operating Highlights

(unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Net loss attributable to common limited partners per unit - basic

$          (5.73)

$          (0.07)

$          (5.74)

$         (0.67)

Cash distributions paid per unit⁽¹⁾

$          0.325

$         0.590

$          0.975

$         1.753

Production revenues (in thousands):

Natural gas

$       57,919

$       79,251

$     181,008

$     239,233

Oil

28,854

38,151

97,100

67,626

Natural gas liquids

3,961

11,997

14,135

31,034

Total production revenues

$       90,734

$     129,399

$     292,243

$     337,893

Production volume:⁽²⁾⁽³⁾

Appalachia: ⁽⁴⁾

Natural gas (Mcfd)

33,950

38,218

32,522

39,083

Oil (Bpd)

326

367

343

390

Natural gas liquids (Bpd)

30

46

34

40

Total (Mcfed)

36,087

40,693

34,782

41,661

Coal-bed Methane^{: (4)}

Natural gas (Mcfd)

128,560

140,177

131,314

130,393

Oil (Bpd)

—

—

—

—

Natural gas liquids (Bpd)

—

—

—

—

Total (Mcfed)

128,560

140,177

131,314

130,393

Barnett/Marble Falls^:

Natural gas (Mcfd)

43,685

57,726

46,868

58,445

Oil (Bpd)

495

1,273

625

1,114

Natural gas liquids (Bpd)

1,898

2,861

2,088

2,732

Total (Mcfed)

58,043

82,535

63,144

81,523

Rangely/Eagle Ford^{: (4)(5)}

Natural gas (Mcfd)

313

—

337

—

Oil (Bpd)

3,573

2,567

3,790

865

Natural gas liquids (Bpd)

313

263

324

89

Total (Mcfed)

23,631

16,978

25,024

5,721

Mississippi Lime/Hunton^:

Natural gas (Mcfd)

6,763

6,679

6,921

6,295

Oil (Bpd)

433

366

443

368

Natural gas liquids (Bpd)

569

545

572

524

Total (Mcfed)

12,771

12,145

13,014

11,651

Other Operating Areas:⁽⁴⁾

Natural gas (Mcfd)

3,143

3,195

3,197

3,287

Oil (Bpd)

16

25

19

24

Natural gas liquids (Bpd)

311

334

248

337

Total (Mcfed)

5,104

5,349

4,799

5,453

Total Production:

Natural gas (Mcfd)

216,414

245,996

221,159

237,503

Oil (Bpd)

4,842

4,598

5,220

2,761

Natural gas liquids (Bpd)

3,121

4,048

3,266

3,722

Total (Mcfed)

264,196

297,876

272,077

276,403

Average sales prices: ⁽³⁾

Natural gas (per Mcf) ⁽⁶⁾

$           3.30

$           3.56

$           3.41

$           3.79

Oil (per Bbl)⁽⁷⁾

$         88.42

$         90.18

$         83.99

$         89.71

Natural gas liquids (per Bbl) ⁽⁸⁾

$         21.42

$         32.21

$         22.17

$         30.54

Production costs:⁽³⁾⁽⁹⁾

$             1.30

$             1.37

$             1.34

$             1.26

        Lease operating expenses per Mcfe

0.19

0.30

0.20

0.27

Production taxes per Mcfe

0.24

0.23

0.24

0.26

Transportation and compression expenses per Mcfe

$             1.74

$             1.89

$             1.78

$             1.79

Total production costs per Mcfe

Depletion per Mcfe⁽³⁾

$             1.53

$             2.26

$             1.57

$             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, the Arkoma Basin in eastern Oklahoma and the County Line area of Wyoming; Rangely/Eagle Ford includes ARP's 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and its production located in southern Texas; Other operating areas include ARP's production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

⁽⁵⁾  

Production volumes and production volumes per day reflect only volumes related to the Rangely field during the three and nine months ended September 30, 2014. Production volumes and volumes per day for the Eagle Ford Acquisition were included effective November 5, 2014.

⁽⁶⁾    

ARP's average sales prices for natural gas before the effects of financial hedging were $2.28 per Mcf and $3.48 per Mcf for the three months ended September 30, 2015 and 2014, respectively, and $2.32 per Mcf and $4.05 per Mcf for the nine months ended September 30, 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 $3.25 per Mcf ($2.23 per Mcf before the effects of financial hedging) and $3.50 per Mcf ($3.43 per Mcf before the effects of financial hedging) for the three months ended September 30, 2015 and 2014, respectively, and $3.35 per Mcf ($2.27 per Mcf before the effects of financial hedging) and $3.69 per Mcf ($3.97 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2015 and 2014, respectively.

⁽⁷⁾    

ARP's average sales prices for oil before the effects of financial hedging were $43.25 per barrel and $91.08 per barrel for the three months ended September 30, 2015 and 2014, respectively, and $46.74 per barrel and $93.45 per barrel for the nine months ended September 30, 2015 and 2014, respectively.

⁽⁸⁾    

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $11.01 per barrel and $32.18 per barrel for the three months ended September 30, 2015 and 2014, respectively, and $13.00 per barrel and $32.16 per barrel for the nine months ended September 30, 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 $1.28 per Mcfe ($1.71 per Mcfe for total production costs) and $1.35 per Mcfe ($1.88 per Mcfe for total production costs) for the three months ended September 30, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.75 per Mcfe for total production costs) and $1.23 per Mcfe ($1.76 per Mcfe for total production costs) for the nine months ended September 30, 2015 and 2014, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

 (unaudited; in thousands)

September 30,

2015

December 31,
2014

Total debt

$     1,505,047

$     1,394,460

Less:  Cash

(2,418)

(15,247)

Total net debt/(cash)

1,502,629

1,379,213

Partners' capital

244,877

947,537

Total capitalization

$     1,747,506

$     2,326,750

Ratio of net debt to capitalization

0.86x

0.59x

ATLAS RESOURCE PARTNERS, L.P

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Maintenance capital expenditures ⁽¹⁾

$    13,456

$    22,400

$    42,788

$    46,300

Expansion capital expenditures

19,343

33,530

59,502

104,279

        Total

$    32,799

$    55,930

$  102,290

$  150,579

⁽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

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Net income (loss)

$     (560,854)

$          1,885

$     (520,092)

$       (27,558)

Acquisition and related costs

1,154

1,595

5,035

12,765

Depreciation, depletion and amortization

40,463

64,578

125,948

176,077

Asset impairment

672,246

–

672,246

–

Amortization of deferred finance costs

3,661

2,436

14,398

6,290

Non-cash stock compensation expense

289

1,988

4,498

6,342

Maintenance capital expenditures⁽²⁾

(13,456)

(13,100)

(42,788)

(34,250)

Preferred unit distributions

(4,275)

(4,475)

(12,613)

(13,298)

Loss on asset sales and disposal

362

92

276

1,686

Cash settlements on commodity derivative contracts⁽³⁾

20,282

–

50,407

–

Unrealized gain on mark-to-market derivatives

(131,065)

–

(209,706)

–

Other

39

(18)

22

(16)

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

$        28,846

$        54,981

$        87,631

$      128,038

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$        69,425

$        78,008

$      212,426

$      204,855

Well construction and completion margin

3,008

7,983

8,304

16,554

Administration and oversight margin

5,495

6,177

7,301

12,072

Well services margin

3,444

3,980

11,833

10,916

Gathering and processing margin

(788)

(153)

(1,360)

(613)

Cash general and administrative expenses⁽⁴⁾

(12,535)

(9,541)

(34,867)

(31,787)

Other, net

59

243

102

327

Adjusted EBITDA⁽¹⁾

68,108

86,697

203,739

212,324

Cash interest expense⁽⁵⁾

(21,531)

(14,141)

(60,707)

(36,738)

Preferred unit distributions

(4,275)

(4,475)

(12,613)

(13,298)

Maintenance capital expenditures⁽²⁾

(13,456)

(13,100)

(42,788)

(34,250)

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

$        28,846

$        54,981

$        87,631

$      128,038

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⁾

−

10,214

−

30,202

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

$        28,846

$        65,195

$        87,631

$      158,240

Distributions Paid⁽⁸⁾

$        32,292

$        52,225

$        91,330

$      145,011

  per limited partner unit

$          0.325

$          0.590

$          0.975

$          1.753

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

$         (3,446)

$        12,970

$         (3,699)

$        13,229

⁽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 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 September 30, 2014, such amounts include net cash generated by the Eagle Ford assets from July 1, 2014 to September 30, 2014 of $23.2 million, less pro forma interest expense of $2.0 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $9.3 million. For the nine months ended September 30, 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 September 30, 2014 of $46.3 million, less pro forma interest expense of $2.4 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $12.0 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 $109.9 million and $258.6 million for the three and nine months ended September 30, 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 November 9, 2015)

Natural Gas

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.19

18,018,000

2016

$    4.23

53,546,000

2017

$    4.22

49,920,000

2018

$    4.17

40,800,000

2019

$    4.02

15,960,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.06

$    4.84

920,000

Put Options – Drilling Partnerships

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.00

480,000

2016

$    4.15

1,440,000

WAHA Basis Swaps

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    (0.0821)

1,600,000

Crude Oil

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

2015^(b)

$    87.62

647,000

2016

$    81.47

1,557,000

2017

$    77.28

1,140,000

2018

$    76.28

1,080,000

2019

$    68.37

540,000

Costless Collars

Average

Average

Production Period

Floor Price

Ceiling Price

Volumes

Ended December 31,

(per bbl)^(a)

(per bbl)^(a)

(bbls)^(a)

2015^(b)

$    83.85

$  110.65

3,250

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 Propane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.0161

64,000

Mt Belvieu Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2481

12,000

Mt Belvieu Iso-Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2631

12,000

Mt Belvieu Natural Gasoline Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.9294

40,000

^(a)

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

^(b)

Reflects hedges covering the last three months of 2015.