ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

 (unaudited; in thousands, except per unit data)

Three Months Ended

Six Months Ended

June 30,

June 30

2015

2014

2015

2014

Revenues:

      Gas and oil production

$        97,260

$      108,237

$      201,509

$    208,494

      Well construction and completion

16,956

16,336

40,611

65,713

      Gathering and processing

2,177

3,758

4,361

8,226

      Administration and oversight

547

4,166

1,806

5,895

      Well services

6,102

6,365

12,726

11,844

      Gain (loss) on mark-to-market derivatives

(26,944)

—

78,641

—

  Other, net

27

35

60

82

          Total revenues

96,125

138,897

339,714

300,254

Costs and expenses:

      Gas and oil production

43,135

43,122

88,633

81,647

      Well construction and completion

14,745

14,206

35,315

57,142

      Gathering and processing

2,516

4,273

4,933

8,686

      Well services

2,139

2,426

4,337

4,908

      General and administrative

13,287

21,315

30,422

37,770

  Depreciation, depletion and amortization

42,494

59,680

85,485

111,499

          Total costs and expenses

118,316

145,022

249,125

301,652

Operating income (loss)

(22,191)

(6,125)

90,589

(1,398)

Gain (loss) on asset sales and disposal

97

9

86

(1,594)

Interest expense

(24,716)

(13,263)

(49,913)

(26,451)

Net income (loss)

(46,810)

(19,379)

40,762

(29,443)

Preferred limited partner dividends

(4,234)

(4,424)

(7,887)

(8,823)

Net income (loss) attributable to common limited
partners and the general partner

$     (23,803)

$        32,875

$    (38,266)

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

General partner's interest

$        (1,021)

$       2,400

$            658

$        4,418

Common limited partners' interest

(50,023)

(26,203)

32,217

(42,684)

Net income (loss) attributable to common limited partners and the general partner

$   (51,044)

$    (23,803)

$     32,875

$    (38,266)

Net income (loss) attributable to common limited partners per unit:

Basic

$          (0.55)

$         (0.35)

$           0.36

$        (0.63)

Diluted

$          (0.55)

$         (0.35)

$           0.36

$        (0.63)

Weighted average common limited partner units outstanding:

Basic

90,516

73,900

88,036

67,595

Diluted

90,516

73,900

88,616

67,595

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

June 30,

December 31,

ASSETS

2015

2014

Current assets:

      Cash and cash equivalents

$                  607

$             15,247

      Accounts receivable

89,169

114,520

      Advances to affiliates

24,856

—

      Current portion of derivative asset

114,710

144,259

      Subscriptions receivable

—

32,398

      Prepaid expenses and other

24,321

26,296

          Total current assets

253,663

332,720

Property, plant and equipment, net

2,226,817

2,263,820

Goodwill and intangible assets, net

14,213

14,330

Long-term derivative asset

150,162

130,602

Other assets, net

56,239

50,081

$        2,701,094

$        2,791,553

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable

$             77,603

$           111,198

      Advances from affiliates

—

2,249

      Liabilities associated with drilling contracts

—

40,611

      Accrued well drilling and completion costs

25,565

80,404

      Distribution payable

13,541

20,876

      Accrued liabilities

54,050

84,235

          Total current liabilities

170,759

339,573

Long-term debt

1,491,612

1,394,460

Asset retirement obligations and other

114,422

109,983

Commitments and contingencies

Partners' Capital:

      General partner's interest

(15,474)

(13,697)

      Preferred limited partners' interests

188,948

163,522

      Common limited partners' interests

611,301

605,065

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

138,350

191,471

Total partners' capital

924,301

947,537

$         2,701,094

$         2,791,553

ATLAS RESOURCE PARTNERS, L.P

Financial and Operating Highlights

(unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Net income (loss) attributable to common limited partners per
unit - basic

$         (0.55)

$         (0.35)

$          0.36

$        (0.63)

Cash distributions paid per unit⁽¹⁾

$          0.325

$         0.583

$          0.650

$         1.163

Production revenues (in thousands):

Natural gas

$       56,548

$       81,780

$     123,089

$     159,982

Oil

35,861

17,192

68,246

29,475

Natural gas liquids

4,851

9,265

10,174

19,037

Total production revenues

$     97,260

$     108,237

$     201,509

$     208,494

Production volume:⁽²⁾⁽³⁾

Appalachia: ⁽⁴⁾

Natural gas (Mcfd)

31,378

37,916

31,796

39,522

Oil (Bpd)

369

388

352

401

Natural gas liquids (Bpd)

35

45

35

37

Total (Mcfed)

33,804

40,513

34,118

42,152

Coal-bed Methane: ⁽⁴⁾

Natural gas (Mcfd)

131,310

131,156

132,714

125,420

Oil (Bpd)

—

—

—

—

Natural gas liquids (Bpd)

—

—

—

—

Total (Mcfed)

131,310

131,156

132,714

125,420

Barnett/Marble Falls:

Natural gas (Mcfd)

47,369

59,711

48,487

58,810

Oil (Bpd)

633

1,231

691

1,034

Natural gas liquids (Bpd)

2,095

2,762

2,184

2,666

Total (Mcfed)

63,740

83,669

65,736

81,009

Rangely/Eagle Ford: ⁽⁴⁾

Natural gas (Mcfd)

200

—

349

—

Oil (Bpd)

3,890

—

3,900

—

Natural gas liquids (Bpd)

302

—

330

—

Total (Mcfed)

25,354

—

25,732

—

Mississippi Lime/Hunton:

Natural gas (Mcfd)

6,429

6,325

7,001

6,100

Oil (Bpd)

383

437

448

369

Natural gas liquids (Bpd)

534

543

574

514

Total (Mcfed)

11,931

12,205

13,137

11,400

Other Operating Areas:⁽⁴⁾

Natural gas (Mcfd)

3,158

3,267

3,224

3,334

Oil (Bpd)

17

27

21

23

Natural gas liquids (Bpd)

227

340

216

339

Total (Mcfed)

4,622

5,470

4,645

5,506

Total Production:⁽³⁾

Natural gas (Mcfd)

219,844

238,375

223,571

233,186

Oil (Bpd)

5,293

2,084

5,412

1,827

Natural gas liquids (Bpd)

3,194

3,689

3,340

3,556

Total (Mcfed)

270,761

273,014

276,083

265,488

Average sales prices: ⁽³⁾

Natural gas (per Mcf) ⁽⁵⁾

$           3.33

$           3.79

$           3.46

$           3.92

Oil (per Bbl)⁽⁶⁾

$         83.19

$         90.66

$         81.98

$         89.12

Natural gas liquids (per Bbl) ⁽⁷⁾

$         22.58

$         27.60

$         22.53

$         29.57

Production costs:⁽³⁾⁽⁸⁾

$             1.36

$             1.22

$             1.36

$             1.19

        Lease operating expenses per Mcfe

0.16

0.24

0.20

0.26

Production taxes per Mcfe

0.24

0.27

0.24

0.28

Transportation and compression expenses per Mcfe

$             1.77

$             1.73

$             1.79

$             1.73

Total production costs per Mcfe

Depletion per Mcfe⁽³⁾

$             1.60

$             2.30

$             1.59

$             2.22

⁽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⁾  

ARP's average sales prices for natural gas before the effects of financial hedging were $2.14 per Mcf and $4.13 per Mcf for the three months ended June 30, 2015 and 2014, respectively, and $2.34 per Mcf and $4.39 per Mcf for the six months ended June 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 $3.28 per Mcf ($2.09 per Mcf before the effects of financial hedging) and $3.77 per Mcf ($4.12 per Mcf before the effects of financial hedging) for the three months ended June 30, 2015 and 2014, respectively, and $3.40 per Mcf ($2.29 per Mcf before the effects of financial hedging) and $3.79 per Mcf ($4.26 per Mcf before the effects of financial hedging) for the six months ended June 30, 2015 and 2014, respectively.

⁽⁶⁾ 

ARP's average sales prices for oil before the effects of financial hedging were $53.35 per barrel and $98.95 per barrel for the three months ended June 30, 2015 and 2014, respectively, and $48.32 per barrel and $96.49 per barrel for the six months ended June 30, 2015 and 2014, respectively.

⁽⁷⁾ 

 ARP's average sales prices for natural gas liquids before the effects of financial hedging were $13.78 per barrel and $28.93 per barrel for the three months ended June 30, 2015 and 2014, respectively, and $13.95 per barrel and $32.15 per barrel for the six months ended June 30, 2015 and 2014, 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 $1.34 per Mcfe ($1.75 per Mcfe for total production costs) and $1.23 per Mcfe ($1.74 per Mcfe for total production costs) for the three months ended June 30, 2015 and 2014, respectively, and $1.34 per Mcfe ($1.77 per Mcfe for total production costs) and $1.16 per Mcfe ($1.70 per Mcfe for total production costs) for the six months ended June 30, 2015 and 2014, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

 (unaudited; in thousands)

June 30,

2015

December 31,
2014

Total debt

$     1,491,612

$     1,394,460

Less:  Cash

(607)

(15,247)

Total net debt/(cash)

1,491,005

1,379,213

Partners' capital

924,301

947,537

Total capitalization

$     2,415,306

$     2,326,750

Ratio of net debt to capitalization

0.62x

0.59x

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Maintenance capital expenditures ⁽¹⁾

$    13,905

$    13,100

$    29,332

$    23,900

Expansion capital expenditures

13,088

41,618

40,159

70,749

        Total

$    26,993

$    54,718

$    69,491

$    94,649

⁽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 income (loss) to non-GAAP
measures⁽¹⁾:

2015

2014

2015

2014

Net income (loss)

$       (46,810)

$       (19,379)

$        40,762

$       (29,443)

Acquisition and related costs

1,710

8,791

3,881

11,170

Depreciation, depletion and amortization

42,494

59,680

85,485

111,499

Amortization of deferred finance costs

3,538

2,042

10,737

3,854

Non-cash stock compensation expense

863

2,009

4,209

4,354

Maintenance capital expenditures⁽²⁾

(13,905)

(10,650)

(29,332)

(21,150)

Preferred unit distributions

(4,253)

(4,424)

(8,338)

(8,823)

(Gain) loss on asset sales and disposal

(97)

(9)

(86)

1,594

Cash settlements on commodity derivative contracts⁽³⁾

14,922

–

30,125

–

Unrealized (gain) loss on mark-to-market derivatives

26,944

–

(78,641)

–

Other

(5)

5

(17)

2

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

$        25,401

$        38,065

$        58,785

$        73,057

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$        69,047

$        65,115

$      143,001

$      126,847

Well construction and completion margin

2,211

2,130

5,296

8,571

Administration and oversight margin

547

4,166

1,806

5,895

Well services margin

3,963

3,939

8,389

6,936

Gathering and processing margin

(339)

(515)

(572)

(460)

Cash general and administrative expenses⁽⁴⁾

(10,714)

(10,515)

(22,332)

(22,246)

Other, net

22

40

43

84

Adjusted EBITDA⁽¹⁾

64,737

64,360

135,631

125,627

Cash interest expense⁽⁵⁾

(21,178)

(11,221)

(39,176)

(22,597)

Preferred unit distributions

(4,253)

(4,424)

(8,338)

(8,823)

Maintenance capital expenditures⁽²⁾

(13,905)

(10,650)

(29,332)

(21,150)

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

$        25,401

$        38,065

$        58,785

$        73,057

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

−

19,988

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

$        25,401

$        52,856

$        58,785

$        93,045

Distributions Paid⁽⁸⁾

$        30,555

$        51,469

$        59,038

$        92,801

  per limited partner unit

$          0.325

$          0.583

$          0.650

$          1.163

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

$         (5,154)

$          1,387

$            (253)

$             244

⁽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 June 30, 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 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

⁽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 $82.0 million and $148.8 million for the three and six months ended June 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 August 6, 2015)

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.19

26,832,246

2016

$    4.23

53,546,320

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)

$    4.16

$    5.00

1,560,000

Put Options – Drilling
Partnerships

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.00

720,000

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)

3,600,000

Crude Oil

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per bbl)^(a)

(bbls)^(a)

2015^(b)

$    87.65

966,000

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

9,750

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

96,000

Mt Belvieu Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2481

21,000

Mt Belvieu Iso-Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2631

21,000

Mt Belvieu Natural Gasoline Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.9446

70,000

^(a)

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

^(b)

Reflects hedges covering the last six months of 2015.