Atlas Resource Partners, L.P. Reports Operating And Financial Results For The First 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 666 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

March 31,

2015

2014

Revenues:

      Gas and oil production

$    100,972

$      96,245

      Well construction and completion

23,655

49,377

      Gathering and processing

2,184

4,468

      Administration and oversight

1,259

1,729

      Well services

6,624

5,479

      Gain on mark-to-market derivatives

104,523

—

Other, net

30

47

          Total revenues

239,247

157,345

Costs and expenses:

      Gas and oil production

44,220

36,792

      Well construction and completion

20,570

42,936

      Gathering and processing

2,417

4,413

      Well services

2,198

2,482

      General and administrative

17,131

16,455

Depreciation, depletion and amortization

41,866

50,237

          Total costs and expenses

128,402

153,315

Operating income

110,845

4,030

Loss on asset sales and disposal

(11)

(1,603)

Interest expense

(25,197)

(13,187)

Net income (loss)

85,637

(10,760)

Preferred limited partner dividends

(3,653)

(4,399)

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

$      81,984

$   (15,159)

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

General partner's interest

$        1,640

$       2,004

Common limited partners' interest

80,344

(17,163)

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

$      81,984

$   (15,159)

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

Basic

$            0.93

$        (0.28)

Diluted

$            0.91

$        (0.28)

Weighted average common limited partner units outstanding:

Basic

85,505

61,219

Diluted

89,985

61,219

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

March 31,

December 31,

ASSETS

2015

2014

Current assets:

      Cash and cash equivalents

$             2,582

$           15,247

      Accounts receivable

94,150

112,038

      Advances to affiliates

21,328

—

      Current portion of derivative asset

145,499

141,366

      Subscriptions receivable

—

32,398

      Prepaid expenses and other

27,856

26,011

          Total current assets

291,415

327,060

Property, plant and equipment, net

2,198,436

2,208,171

Goodwill and intangible assets, net

14,271

14,330

Long-term derivative asset

186,718

127,933

Other assets, net

56,736

50,081

$     2,747,576

$     2,727,575

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:

      Accounts payable

$           93,548

$         109,049

      Advances from affiliates

—

4,271

      Liabilities associated with drilling contracts

16,956

40,611

      Accrued well drilling and completion costs

42,552

80,404

      Distribution payable

12,405

20,876

      Accrued liabilities

41,745

83,847

          Total current liabilities

207,206

339,058

Long-term debt

1,500,178

1,394,460

Asset retirement obligations and other

110,562

108,561

Commitments and contingencies

Partners' Capital:

      General partner's interest

(13,842)

(13,697)

      Preferred limited partners' interests

182,968

163,522

      Common limited partners' interests

600,015

548,586

      Class C common limited partner warrants

1,176

1,176

      Accumulated other comprehensive income

159,313

185,909

Total partners' capital

929,630

885,496

$      2,747,576

$      2,727,575

ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)

Three Months Ended

March 31,

2015

2014

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

$                0.93

$              (0.28)

Cash distributions paid per unit⁽¹⁾

$              0.325

$              0.580

Production revenues (in thousands):

Natural gas

$         63,264

$        74,190

Oil

32,385

12,283

Natural gas liquids

5,323

9,772

Total production revenues

$     100,972

$       96,245

Production volume:⁽²⁾⁽³⁾

Appalachia: ⁽⁴⁾

Natural gas (Mcfd)

32,219

41,146

Oil (Bpd)

334

415

Natural gas liquids (Bpd)

35

29

Total (Mcfed)

34,436

43,810

Coal-bed Methane^{: (4)}

Natural gas (Mcfd)

123,481

108,368

Oil (Bpd)

—

—

Natural gas liquids (Bpd)

—

—

Total (Mcfed)

123,481

108,368

Barnett/Marble Falls^:

Natural gas (Mcfd)

49,617

57,898

Oil (Bpd)

749

834

Natural gas liquids (Bpd)

2,274

2,570

Total (Mcfed)

67,755

78,319

Rangely/Eagle Ford^{: (4)}

Natural gas (Mcfd)

500

—

Oil (Bpd)

3,911

—

Natural gas liquids (Bpd)

359

—

Total (Mcfed)

26,115

—

Mississippi Lime/Hunton^:

Natural gas (Mcfd)

7,579

5,873

Oil (Bpd)

514

301

Natural gas liquids (Bpd)

615

485

Total (Mcfed)

14,357

10,587

Other Operating Areas:⁽⁴⁾

Natural gas (Mcfd)

3,291

3,402

Oil (Bpd)

25

19

Natural gas liquids (Bpd)

204

338

Total (Mcfed)

4,668

5,544

Total Production:⁽³⁾

Natural gas (Mcfd)

216,687

216,688

Oil (Bpd)

5,533

1,568

Natural gas liquids (Bpd)

3,488

3,422

Total (Mcfed)

270,811

246,628

Average sales prices: ⁽³⁾

Natural gas (per Mcf) ⁽⁵⁾

$           3.59

$           4.07

Oil (per Bbl)⁽⁶⁾

$         80.81

$         87.04

Natural gas liquids (per Bbl) ⁽⁷⁾

$         22.49

$         31.73

Production costs:⁽³⁾⁽⁸⁾

        Lease operating expenses per Mcfe

$           1.37

$           1.17

Production taxes per Mcfe

0.24

0.27

Transportation and compression expenses per Mcfe

0.22

0.29

Total production costs per Mcfe

$           1.84

$           1.73

Depletion per Mcfe⁽³⁾

$           1.60

$           2.16

⁽¹⁾

Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each month within each quarter, based upon the distributable cash flow generated during the respective period. 

⁽²⁾

Production quantities consist of the sum of (i) ARP's proportionate share of production from wells in which it has a direct interest, based on ARP's proportionate net revenue interest in such wells, and (ii) ARP's proportionate share of production from wells owned by the investment partnerships in which ARP has an interest, based on its equity interest in each such partnership and based on each partnership's proportionate net revenue interest in these wells.

⁽³⁾

"Mcf" and "Mcfd" represent thousand cubic feet and thousand cubic feet per day; "Mcfe" and "Mcfed" represent thousand cubic feet equivalents and thousand cubic feet equivalents per day, and "Bbl" and "Bpd" represent barrels and barrels per day.  Barrels are converted to Mcfe using the ratio of six Mcf's to one barrel.

⁽⁴⁾

Appalachia includes ARP's production located in Pennsylvania, Ohio, New York and West Virginia (excluding the Cedar Bluff area); Coal-bed methane includes ARP's production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Cedar Bluff area of West Virginia and Virginia, and the 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 $2.53 per Mcf and $4.68 per Mcf for the three months ended March 31, 2015 and 2014, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships. Including the effects of subordination, average natural gas sales prices were $3.53 per Mcf ($2.48 per Mcf before the effects of financial hedging) and $3.80 per Mcf ($4.42 per Mcf before the effects of financial hedging) for the three months ended March 31, 2015 and 2014, respectively.

⁽⁶⁾

ARP's average sales prices for oil before the effects of financial hedging were $43.46 per barrel and $93.18 per barrel for the three months ended March 31, 2015 and 2014, respectively.

⁽⁷⁾

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $14.10 per barrel and $35.65 per barrel for the three months ended March 31, 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 $1.35 per Mcfe ($1.81 per Mcfe for total production costs) and $1.10 per Mcfe ($1.66 per Mcfe for total production costs) for the three months ended March 31, 2015 and 2014, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)

March 31,

2015

December 31,

2014

Total debt

$     1,500,178

$     1,394,460

Less:  Cash

(2,582)

(15,247)

Total net debt/(cash)

1,497,596

1,379,213

Partners' capital

929,630

885,496

Total capitalization

$     2,427,226

$     2,264,709

Ratio of net debt to capitalization

0.62x

0.61x

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

Three Months Ended

March 31,

2015

Maintenance capital expenditures ⁽¹⁾

$      15,427

$      10,800

Expansion capital expenditures

27,071

29,097

        Total

$      42,498

$      39,897

⁽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

March 31,

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

2015

2014

Net income (loss)

$      85,637

$     (10,760)

Acquisition and related costs

2,171

2,379

Depreciation, depletion and amortization

41,866

50,237

Amortization of deferred finance costs

7,199

1,811

Non-cash stock compensation expense

3,346

2,345

Maintenance capital expenditures⁽²⁾

(15,427)

(10,500)

Preferred unit distributions

(4,085)

(4,399)

Loss on asset sales and disposal

11

1,603

Cash settlements on commodity derivative contracts⁽³⁾

15,203

–

Unrealized gain on mark-to-market derivatives

(104,523)

–

Other

(12)

(3)

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

$      31,386

$      32,713

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

$      71,955

$      59,453

Well construction and completion margin

3,085

6,441

Administration and oversight margin

1,259

1,729

Well services margin

4,426

2,997

Gathering and processing margin

(233)

55

Cash general and administrative expenses⁽⁴⁾

(11,614)

(11,731)

Other, net

18

44

Adjusted EBITDA⁽¹⁾

68,896

58,988

Cash interest expense⁽⁵⁾

(17,998)

(11,376)

Preferred unit distributions

(4,085)

(4,399)

Maintenance capital expenditures⁽²⁾

(15,427)

(10,500)

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

$      31,386

$      32,713

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⁾

−

5,197

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

$      31,386

$      37,910

Distributions Paid⁽⁸⁾

$      28,483

$      41,332

  per limited partner unit

$        0.325

$        0.580

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

$         2,903

$       (3,422)

⁽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; 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 March 31, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to March 31, 2014 of $5.5 million, less estimated maintenance capital expenditures of $0.3 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 $64.5 million for the three months ended March 31, 2014.

⁽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 May 5, 2015)

Natural Gas

Fixed Price Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.21

40,053,369

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)

$    4.21

$    5.09

2,520,000

Put Options – Drilling Partnerships

Average

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per mmbtu)^(a)

(mmbtus)^(a)

2015^(b)

$    4.00

1,080,000

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)

$    87.59

1,445,000

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

19,500

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

144,000

          Mt Belvieu Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2481

24,000

Mt Belvieu Iso-Butane Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.2631

27,000

Mt Belvieu Natural Gasoline Swaps

Average

Production Period

Fixed Price

Volumes

Ended December 31,

(per gallon)

(bbls)^(a)

2015^(b)

$    1.9558

90,000

^(a)

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

^(b)

Reflects hedges covering the last nine months of 2015.