• Net production volume per day:

         Natural gas (mcfd)

221,443

         Crude oil (bpd)

7,179

         NGL (bpd)

4,408

               Total (mcfed)

290,964

ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)

September 30,

December 31,

ASSETS

2014

2013

Current assets:

      Cash and cash equivalents

$               5,167

$               1,828

      Accounts receivable

99,656

58,822

      Current portion of derivative asset

21,050

1,891

      Subscriptions receivable

62,840

47,692

      Prepaid expenses and other

24,783

10,097

          Total current assets

213,496

120,330

Property, plant and equipment, net

2,657,060

2,120,818

Goodwill and intangible assets, net

32,543

32,747

Long-term derivative asset

30,826

27,084

Other assets, net

52,477

42,821

$        2,986,402

$        2,343,800

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable

$           104,275

$             69,346

      Advances from affiliates

26,342

26,742

      Liabilities associated with drilling contracts

—

49,377

      Current portion of derivative liability

1,792

6,353

      Accrued well drilling and completion costs

100,226

40,481

      Distribution payable

18,901

—

      Accrued liabilities

34,997

51,416

          Total current liabilities

286,533

243,715

Long-term debt

1,283,022

942,334

Asset retirement obligations and other

103,219

90,460

Commitments and contingencies

Partners' Capital:

      General partner's interest

(890)

4,482

      Preferred limited partners' interests

180,568

183,477

      Common limited partners' interests

1,079,476

852,457

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

53,298

25,699

Total partners' capital

1,313,628

1,067,291

$         2,986,402

$         2,343,800

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

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net loss attributable to common limited partners per unit - basic

$        (0.08)

$         (0.74)

$         (0.70)

$         (1.21)

Cash distributions paid per unit(1)

$       0.590

$         0.560

$         1.753

$         1.610

Production revenues (in thousands):

Natural gas 

$     75,246

$       57,350

$     227,036

$     114,789

Oil

38,151

12,993

67,626

32,394

Natural gas liquids

11,997

9,989

31,034

26,307

Total production revenues

$     125,394

$       80,332

$     325,696

$     173,490

Production volume:(2)(3)

Appalachia: (4)

Natural gas (Mcfd)

38,218

38,594

39,083

33,651

Oil (Bpd)

367

312

390

291

Natural gas liquids (Bpd)

46

12

40

5

Total (Mcfed)

40,693

40,541

41,661

35,428

Coal-bed Methane: (4)(5)

Natural gas (Mcfd)

128,444

115,354

118,833

25,775

Oil (Bpd)

—

—

—

—

Natural gas liquids (Bpd)

—

—

—

—

Total (Mcfed)

128,444

115,354

118,833

25,775

Barnett/Marble Falls:

Natural gas (Mcfd)

57,726

66,145

58,445

66,208

Oil (Bpd)

1,273

899

1,114

847

Natural gas liquids (Bpd)

2,861

2,961

2,732

2,757

Total (Mcfed)

82,535

89,306

81,523

87,834

Rangely:  (4)

Natural gas (Mcfd)

—

—

—

—

Oil (Bpd)

2,567

—

865

—

Natural gas liquids (Bpd)

263

—

89

—

Total (Mcfed)

16,978

—

5,721

—

Mississippi Lime/Hunton:

Natural gas (Mcfd)

6,679

5,475

6,295

4,739

Oil (Bpd)

366

285

368

144

Natural gas liquids (Bpd)

545

366

524

285

Total (Mcfed)

12,145

9,382

11,651

7,315

Other Operating Areas:(4)

Natural gas (Mcfd)

3,195

4,321

3,287

4,571

Oil (Bpd)

25

21

24

19

Natural gas liquids (Bpd)

334

395

337

394

Total (Mcfed)

5,349

6,815

5,453

7,044

Total Production:(3)

Natural gas (Mcfd)

234,263

191,020

225,943

134,945

Oil (Bpd)

4,598

1,517

2,761

1,301

Natural gas liquids (Bpd)

4,048

3,734

3,722

3,441

Total (Mcfed)

286,143

222,529

264,843

163,397

Average sales prices: (3)

Natural gas (per Mcf) (6)

$           3.55

$           3.46

$           3.79

$           3.39

Oil (per Bbl)(7)

$         90.18

$         93.07

$         89.71

$         91.19

Natural gas liquids (per Bbl) (8)

$         32.21

$         29.08

$         30.54

$         28.01

Production costs:(3)(9)

        Lease operating expenses per Mcfe

$           1.39

$           1.15

$           1.27

$           1.12

Production taxes per Mcfe

0.30

0.11

0.27

0.17

Transportation and compression expenses per Mcfe

0.22

0.24

0.26

0.22

Total production costs per Mcfe

$           1.91

$           1.50

$           1.80

$           1.51

Depletion per Mcfe(3)

$           2.28

$           1.95

$           2.26

$           1.80

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

(5)  

Volumetric production per day for coal-bed methane for the three months ended September 30, 2013 includes production per day for the 61-day period from August 1, 2013, the date ARP began recognizing production from the assets following the completion of the EP Energy Acquisition, through September 30, 2013.  Total coal-bed methane production per day for the nine months ended September 30, 2013 represents volume production for the full 273-day period.  Total production per day represents total production volume over the 92 and 273 days within the three and nine months ended September 30, 2014, respectively.

(6)    

ARP's average sales prices for natural gas before the effects of financial hedging were $3.47 per Mcf and $3.20 per Mcf for the three months ended September 30, 2014 and 2013, respectively, and $4.07 per Mcf and $3.19 per Mcf for the nine months ended September 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 $3.49 per Mcf ($3.41 per Mcf before the effects of financial hedging) and $3.26 per Mcf ($3.01 per Mcf before the effects of financial hedging) for the three months ended September 30, 2014 and 2013, respectively, and $3.68 per Mcf ($3.96 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.92 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2014 and 2013, respectively.

(7)    

ARP's average sales prices for oil before the effects of financial hedging were $91.08 per barrel and $104.03 per barrel for the three months ended September 30, 2014 and 2013, respectively, and $93.45 per barrel and $96.50 per barrel for the nine months ended September 30, 2014 and 2013, respectively.

(8)    

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $32.18 per barrel and $30.10 per barrel for the three months ended September 30, 2014 and 2013, respectively, and $32.16 per barrel and $28.52 per barrel for the nine months ended September 30, 2014 and 2013, 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 $1.37 per Mcfe ($1.90 per Mcfe for total production costs) and $1.09 per Mcfe ($1.44 per Mcfe for total production costs) for the three months ended September 30, 2014 and 2013, respectively, and $1.25 per Mcfe ($1.78 per Mcfe for total production costs) and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, respectively.

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

September 30,

2014

December 31,
2013

Total debt

$     1,283,022

$         942,334

Less:  Cash

(5,167)

(1,828)

Total net debt/(cash)

1,277,855

940,506

Partners' capital  

1,313,628

1,067,291

Total capitalization

$     2,591,483

$     2,007,797

Ratio of net debt to capitalization

0.49x

0.47x

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

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Maintenance capital expenditures(1)

$    22,400

$    10,000

$    46,300

$    21,000

Expansion capital expenditures

33,530

63,944

104,185

182,996

        Total

$    55,930

$    73,944

$  150,485

$  203,996

(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,

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

2014

2013

2014

2013

Net income (loss)

$          1,075

$       (39,697)

$       (30,207)

$       (51,250)

Acquisition and related costs

1,595

19,417

12,765

25,897

Depreciation, depletion and amortization

62,852

41,656

171,090

85,061

Amortization of deferred finance costs

2,436

2,847

6,290

8,642

Non-cash stock compensation expense

1,988

2,959

6,342

10,208

Maintenance capital expenditures(2)

(13,100)

(9,167)

(34,250)

(17,667)

Preferred unit distribution

(4,475)

(4,248)

(13,298)

(8,277)

Loss on asset sales and disposal

92

661

1,686

2,035

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

−

13,308

−

14,617

Other

(18)

−

(16)

−

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

$        52,445

$        27,736

$      120,402

$        69,266

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$        75,472

$        50,913

$      197,219

$      109,820

Well construction and completion margin

7,983

1,430

16,554

12,038

Administration and oversight margin

6,177

4,447

12,072

8,923

Well services margin

3,980

2,637

10,916

7,694

Gathering and processing margin

(153)

(804)

(613)

(2,128)

Cash general and administrative expenses(4)

(9,541)

(9,607)

(31,787)

(27,662)

Other, net

243

36

327

28

Adjusted EBITDA(1)

84,161

49,052

204,688

108,713

Cash interest expense(5)

(14,141)

(7,901)

(36,738)

(13,503)

Preferred unit distribution

(4,475)

(4,248)

(13,298)

(8,277)

Maintenance capital expenditures(2)

(13,100)

(9,167)

(34,250)

(17,667)

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

$        52,445

$        27,736

$      120,402

$        69,266

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

5,244

30,202

25,791

Well construction and completion margin earned(7)

—

4,760

—

4,760

Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(8)

$        62,659

$        37,740

$      150,604

$        99,817

Distributions Paid(9)

$        52,225

$        35,733

$      145,011

$        93,083

  per limited partner unit

$        0.590

$        0.560

$        1.753

$        1.610

Excess of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(10)

$        10,434

$          2,007

$          5,593

$          6,734

(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 Amended 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;
• 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; 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; 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)

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 3rd quarter 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 3rd quarter 2013, such amounts include pro forma net cash generated by the EP Energy assets from July 1, 2013 to July 31, 2013 of $6.9 million, less pro forma interest expense of $0.8 million and estimated maintenance capital expenditures of $0.8 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.  For the nine months ended September 30, 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to July 31, 2013 of $32.4 million, less pro forma interest expense of $3.3 million and estimated maintenance capital expenditures of $3.3 million. 

(7)

This amount reflects well construction and completion margin from the deployment of capital for the investment partnership programs during the 3rd quarter 2013 for which ARP was required to defer recognition under GAAP until additional investor funds were received.  Under ARP's annual investment partnership programs, investor funds must be received by the particular investment partnership by December 31st of that calendar year to be eligible for an investment in that program. 

(8)

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 $107.4 million and $60.7 million for the three months ended September 30, 2014 and 2013, respectively, and $251.1 million and $145.9 million for the nine months ended September 30, 2014 and 2013, respectively. 

(9)

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. 

(10)

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 November 10, 2014)

Natural Gas

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)(a)

(mmbtus)(a)

   2014(b)

$    4.15

15,038,244

2015

$    4.24

52,584,492

2016

$    4.31

45,746,320

2017

$    4.37

35,640,000

2018

$    4.38

18,960,000

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

960,000

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

450,000

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)

2,700,000

2015

$    (0.0675)

3,000,000

NGPL Basis Swaps

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)(a)

(mmbtus)(a)

   2014(b)

$    (0.1080)

2,250,000

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

15,000

Mt Belvieu Propane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)(a)

   2014(b)

$    0.9996

73,500

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

9,000

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

9,000

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

33,000

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)

$    95.09

439,500

2015

$    90.65

1,743,000

2016

$    87.36

1,209,000

2017

$    85.67

672,000

2018

$    85.47

540,000

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

10,290

2015

$    83.85

$  110.65

29,250

(a)

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

(b)

Reflects hedges covering the last three months of 2014.