Atlas Resource Partners, L.P. Reports Operating And Financial Results For The Fourth Quarter And Full Year 2014

PHILADELPHIA, March 2, 2015 /PRNewswire/ --

  • Adjusted EBITDA, including discretionary adjustments by the Board of Directors of the General Partner, was $87.1 million(1) for the fourth quarter 2014, an approximate 39% increase from the prior year quarter
  • Distributable cash flow, including discretionary adjustments by the Board of Directors of the General Partner, was $47.1 million(1) for the fourth quarter 2014, an approximate 29% increase from the prior year quarter
  • ARP updated its 2015 financial outlook, including full year distribution guidance of $1.30 per unit at an expected coverage range of 1.2x to 1.4x
  • ARP will discuss fourth quarter and full year 2014 financial and operational results on a conference call at 9AM ET on Monday, March 2nd

Atlas Resource Partners, L.P. ARP ("ARP" or "the Company") has reported operating and financial results for the fourth quarter and full year 2014.

Matthew A. Jones, President of ARP, stated, "Our business experienced yet another year of substantial growth and development. We believe that our diversified oil & gas asset base, cash flow from both our production and partnership management business, and the financial actions we have recently taken will allow us to add stability in the current environment."

  • Fourth quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $87.1 million(1), compared to $107.4 million for the third quarter 2014, and $62.6 million for the prior year comparable quarter. Full year 2014 Adjusted EBITDA, including discretionary adjustments by the Board of Directors of the General Partner, was $338.2 million, which was 62% higher than full year 2013 Adjusted EBITDA of $208.6 million. The decrease from the sequential quarter was primarily due to lower realized production margin from the Company's Eagle Ford and Rangely production, which experienced lower volumes during the period. The variance in production volumes in these areas was attributable to scheduled maintenance activity in the Rangeley Field, and temporary well shut-ins from offset well completions in the Eagle Ford, as well as expected decline from flush Eagle Ford production in prior periods. Results were also affected by lower partnership margin and higher cash general and administrative costs. The increase in Adjusted EBITDA compared to the prior year quarter and full year 2013 was due to cash flow contribution from recently acquired assets in the Eagle Ford shale in south Texas, the acquisition of the Rangely Field oil and liquids assets in northwest Colorado in June 2014, and the acquisition of the GeoMet natural gas assets in West Virginia in May 2014.
  • Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $47.1 million(1), or approximately $0.51 per common unit, for the fourth quarter 2014, compared to $62.7 million for the third quarter 2014 and $36.6 million for the prior year comparable quarter. Full year 2014 Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner was $197.7 million, a 45% increase from the full year 2013 Distributable Cash Flow of $136.4 million. Please see above for explanations of the variances in Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner.
  • ARP paid monthly cash distributions totaling approximately $0.59 per limited partner unit for the fourth quarter 2014. On February 23, 2015, ARP announced the January 2015 monthly distribution of $0.1083 per unit ($1.30 per unit on an annualized basis), which will be paid on March 17, 2015 to unitholders of record as of March 10, 2015. ARP expects to achieve a distribution coverage ratio of 1.2x to 1.4x for the full year 2015 at the current distribution level, assuming current forward strip prices for oil and natural gas.
  • The Company's partnership management business raised $166.8 million from its Series 34 – 2014 private placement fundraising in 2014. This amount is over 11% higher than the fundraising amount for its 2013 program, and the Series 34 capital is expected to be deployed to drill new wells in the Eagle Ford Shale, Utica Shale, Mississippi Lime and Marble Falls.
  • On a GAAP basis, net loss was $580.8 million for the fourth quarter 2014 compared with net income of $1.1 million for the third quarter 2014 and a net loss of $40.0 million for the prior year comparable period. The net loss for the fourth quarter 2014 was principally generated by non-cash expenses, specifically depreciation and amortization and an asset impairment charge on certain oil and gas properties due to recent declines in forward commodity prices. Full year 2014 net loss was $611.0 million, as compared to a net loss of $91.2 million for the full year 2013. The full year net loss increased for similar reasons as mentioned above.

2015 Financial Outlook

ARP has provided an updated financial outlook for the full year 2015, which includes expected cash distributions of $1.30 per unit with distribution coverage of approximately 1.2x to 1.4x. The following are several of the key assumptions included in the forecast:

  • Net production volume per day of approximately 289.5 million cubic feet equivalents per day ("Mmcfed")
  • Net realized natural gas price after hedges of $3.58/mcf (72% hedged)
  • Net realized crude oil price after hedges of $73.76/bbl (68% hedged)
  • Total net production costs of approximately $1.90 per thousand cubic feet equivalent
  • $150.0 million in partnership management funds raised for the year ending December 31, 2015
  • Total capital expenditures of approximately $172 million for the year ending December 31, 2015, including approximately $62 million of maintenance capital expenditures
  • ARP's forecast for full year 2015 does not assume any consummated acquisitions or net proceeds from the issuance of additional limited partner units.

Recent Events

Merger Transaction Between Targa Resources, Atlas Energy and Atlas Pipeline

On February 27, 2015, ARP's parent company, Atlas Energy, L.P. ATLS, and ATLS' midstream subsidiary, Atlas Pipeline Partners, L.P. APL, completed their previously announced merger transactions of Atlas Energy with a subsidiary of Targa Resources Corp. TRGP ("TRC") ("ATLS Merger") and Atlas Pipeline with a subsidiary of Targa Resources Partners LP ("TRP") ("APL Merger"). The consummation of the mergers followed the approval of the mergers by ATLS and APL unitholders as well as TRC stockholders at special meetings which occurred on Friday, February 20, 2015.

Immediately prior to the closing of the acquisition of ATLS by TRC, ATLS transferred its non-midstream assets to Atlas Energy Group, LLC ("AEG"), a wholly owned subsidiary of ATLS, and then distributed to the ATLS unitholders common units representing a 100% limited liability company interest in AEG. Among other interests, AEG now owns 100% of the general partner interest and a 28% limited partner interest in ARP.

Year End 2014 Oil & Gas Reserves

During the 2014 calendar year, ARP continued to increase its oil & gas reserves and undeveloped properties through both strategic acquisitions as well as organic development. This activity was highlighted by ARP's acquisitions of natural gas properties in West Virginia (GeoMet), mature oil properties in the Rangely Field in northwest Colorado, and oil-rich reserves in the Eagle Ford shale in south Texas. These acquisitions were accompanied by ongoing development in the Company's key operating areas of the Mississippi Lime, Marble Falls and the Utica Shale.

As of December 31, 2014, based on the SEC average price assumptions of $4.35 per mcf for natural gas and $94.99 per barrel for crude oil, net proved oil and gas reserves were approximately 1.429 trillion cubic feet equivalents ("Tcfe"), an increase of approximately 22% from the year end 2013 reserve levels. The year end 2014 reserves were valued at a PV-10 amount of approximately $1.99 billion, which does not include the value of ARP's commodity derivatives.  The fair value of ARP's commodity derivatives at December 31, 2014 was approximately $266.5 million. Approximately 77% of ARP's reserves were proved developed, compared to 68% at the end of 2013.

E&P Operating Results

  • Average net daily production for the fourth quarter 2014 was 285.1 Mmcfed, approximately 10% higher than the prior year comparable quarter. The increase in net production from the prior year quarter was due primarily to the acquisition of the Eagle Ford assets in November 2014, as well as the Rangely Field assets in June 2014 and the GeoMet natural gas production assets in May 2014.
  • ARP's net realized price for natural gas including the effect of hedge positions was $3.66 per mcf for the fourth quarter, compared to $3.55 per mcf for the third quarter 2014. Net realized oil prices including the effect of hedge positions averaged $84.81 per barrel for the fourth quarter 2014, compared to $90.18 for the third quarter 2014.
  • Investment partnership margin contributed $13.6 million to Adjusted EBITDA and distributable cash flow for the fourth quarter 2014 compared with $18.1 million for the sequential quarter.  The $4.5 million decrease in investment partnership margin was due to higher amounts of capital deployed during the 3rd quarter due to scheduled changes in well drilling activity.

Hedge Positions

  • ARP continued to expand its commodity hedge positions on its existing production during the fourth quarter and full year 2014. A summary of ARP's derivative positions as of March 2, 2015 is provided in the financial tables of this release. During the fourth quarter 2014, ARP was approximately 75% hedged on its net natural gas production and approximately 90% hedged on its net oil production.

Corporate Expenses & Capital Position

  • Cash general and administrative expense was $13.1 million for the fourth quarter 2014, $3.6 million higher than the third quarter 2014 and $5.3 million higher than the prior year fourth quarter. The increase compared with prior periods was due primarily to higher costs related to increased personnel managing ARP's expanded asset base, as well as higher administrative and marketing costs associated with ARP's 2014 partnership program.
  • Cash interest expense was $16.0 million for the fourth quarter 2014, $1.8 million higher than the third quarter 2014 and $4.8 million higher than the prior year fourth quarter. The increase from the third quarter 2014 prior periods was primarily due to higher levels of borrowing used to expand ARP's operations over the prior periods, including the issuance of an additional $75 million of the Company's 9.25% Senior Notes due in 2021, from which the proceeds were utilized to purchase the Eagle Ford Shale assets during the fourth quarter 2014. The increase compared to the prior year quarter was due to the issuance of the 9.25% Senior Notes above, as well as a $100 million follow-on offering in May 2014 of the Company's 7.75% Senior Notes due in 2021 to partially fund ARP's acquisition of oil producing properties in the Rangely Field in northwest Colorado.
  • At December 31, 2014, ARP had $1.394 billion of total debt, including $696.0 million outstanding under its revolving credit facility. The increase in total debt from the third quarter 2014 was due primarily to the issuance of the additional 9.25% Senior Notes during the fourth quarter 2014 to partially fund the Eagle Ford acquisition on November 5, 2014.

ARP will be discussing its fourth quarter and full year 2014 results on an investor call with management on Monday, March 2, 2015 at 9:00 am Eastern Time. Interested parties are invited to access the live webcast the investor call by going to the Investor Relations section of Atlas Resource's website at www.atlasresourcepartners.com.  For those unavailable to listen to the live broadcast, the replay of the webcast will be available following the live call on the Atlas Resource website and telephonically beginning at approximately 1:00 p.m. ET on March 2, 2015 by dialing 855-859-2056, passcode: 89716873.

Atlas Resource Partners, L.P. ARP is an exploration & production master limited partnership which owns an interest in over 14,500 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM), Black Warrior Basin (AL) and the Rangely Field in Colorado.  ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Energy Group, LLC ATLS is a master limited partnership which owns the following interests: all of the general partner interest, incentive distribution rights and an approximate 28% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P.; the general partner interests, incentive distribution rights and limited partner interests in its private E&P development subsidiary; and a general partner interest in Lightfoot Capital Partners, an entity that invests directly in energy-related businesses and assets. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed within this press release are forward-looking statements.  Although Atlas Resource Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained.  Atlas Resource Partners does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. This document contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements.  ARP cautions readers that any forward-looking information is not a guarantee of future performance.  Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource potential, ARP's plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, those associated with general economic and business conditions; ARP's ability to realize the benefits of its acquisitions; changes in commodity prices; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP's level of indebtedness; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; and other risks, assumptions and uncertainties detailed from time to time in ARP's reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and we assume no obligation to update such statements, except as may be required by applicable law.

(1)

A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 8 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


Years Ended


December 31,


December 31,


2014


2013


2014


2013

Revenues:








      Gas and oil production

$      128,261


$        93,293


$      453,957


$      266,783

      Well construction and completion

46,647


75,590


173,564


167,883

      Gathering and processing

2,820


4,037


14,107


15,676

      Administration and oversight

3,492


3,354


15,564


12,277

      Well services

6,518


4,789


24,959


19,492

Other, net

3,066


133


3,409


(14,456)

          Total revenues

190,804


181,196


685,560


467,655









Costs and expenses:








      Gas and oil production

47,717


33,567


176,194


97,237

      Well construction and completion

40,562


65,730


150,925


145,985

      Gathering and processing

3,625


4,245


15,525


18,012

      Well services      

2,482


2,506


10,007


9,515

      General and administrative

21,455


14,296


72,349


78,063

Depreciation, depletion and amortization

62,641


51,702


233,731


136,763

Asset impairment

573,774


38,014


573,774


38,014

          Total costs and expenses      

752,256


210,060


1,232,505


523,589









Operating loss

(561,452)


(28,864)


(546,945)


(55,934)









Gain (loss) on asset sales and disposal

(183)


1,048


(1,869)


(987)

Interest expense

(19,116)


(12,179)


(62,144)


(34,324)









Net loss

(580,751)


(39,995)


(610,958)


(91,245)









Preferred limited partner dividends

(5,969)


(4,400)


(19,267)


(11,992)

Net loss attributable to common limited partners and the general partner

 

$     (586,720)


 

$     (44,395)


 

$     (630,225)


 

$     (103,237)









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




General partner's interest

$        (8,673)


$       1,209


$        (1,299)


$       3,344

Common limited partners' interest

(578,047)


(45,604)


(628,926)


(106,581)

Net loss attributable to common limited partners and the general partner

$    (586,720)


 

$    (44,395)


$    (630,225)


 

$  (103,237)









Net loss attributable to common limited partners per unit:







Basic and Diluted

$          (7.06)


$         (0.77)


$          (8.42)


$        (2.03)









Weighted average common limited partner units outstanding:

Basic and Diluted

81,919


59,447


74,716


52,528

                                                                                                                                                                       

 

 


ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)




December 31,

ASSETS


2014


2013

Current assets:





      Cash and cash equivalents


$             15,247


$               1,828

      Accounts receivable


112,038


58,822

      Current portion of derivative asset


141,366


1,891

      Subscriptions receivable


32,398


47,692

      Prepaid expenses and other


26,011


10,097

          Total current assets


327,060


120,330






Property, plant and equipment, net


2,208,171


2,120,818

Goodwill and intangible assets, net


14,330


32,747

Long-term derivative asset


127,933


27,084

Other assets, net


50,081


42,821



$        2,727,575


$        2,343,800






LIABILITIES AND PARTNERS' CAPITAL










Current liabilities:





      Accounts payable      


$           109,049


$             69,346

      Advances from affiliates


4,271


26,742

      Liabilities associated with drilling contracts


40,611


49,377

      Current portion of derivative liability



6,353

      Accrued well drilling and completion costs


80,404


40,481

      Distribution payable


20,876


      Accrued liabilities


83,847


51,416

          Total current liabilities


339,058


243,715






Long-term debt


1,394,460


942,334

Asset retirement obligations and other


108,561


90,460






Commitments and contingencies










Partners' Capital:





      General partner's interest


(13,697)


4,482

      Preferred limited partners' interests


163,522


183,477

      Common limited partners' interests


548,586


852,457

      Class C common limited partner warrants


1,176


1,176

      Accumulated other comprehensive income


185,909


25,699

Total partners' capital


885,496


1,067,291



$         2,727,575


$         2,343,800

 

 


ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)



Three Months Ended


Years Ended


December 31,


December 31,


2014


2013


2014


2013









Net loss attributable to common limited partners per unit - basic

$         (7.06)


$            (0.77)


$         (8.42)


$          (2.03)









Cash distributions paid per unit(1)

$          0.590


$         0.580


$           2.343


$         2.190









Production revenues (in thousands):








Natural gas 

$       75,790


$       71,440


$     302,826


$     186,229

Oil

42,444


11,766


110,070


44,160

Natural gas liquids

10,027


10,087


41,061


36,394

Total production revenues

$     128,261


$       93,293


$     453,957


$     266,783









Production volume:(2)(3)








Appalachia: (4)








Natural gas (Mcfd)

35,420


45,768


38,160


36,705

Oil (Bpd)

355


452


381


332

Natural gas liquids (Bpd)

43


70


41


22

Total (Mcfed)

37,807


48,904


40,689


38,825

Coal-bed Methane: (4)








Natural gas (Mcfd)

126,511


113,346


120,768


47,848

Oil (Bpd)




Natural gas liquids (Bpd)




Total (Mcfed)

126,511


113,346


120,768


47,848

Barnett/Marble Falls:








Natural gas (Mcfd)

54,143


61,625


57,361


65,053

Oil (Bpd)

923


692


1,066


808

Natural gas liquids (Bpd)

2,598


2,734


2,698


2,751

Total (Mcfed)

75,264


82,179


79,946


86,409

Rangely/Eagle Ford: (4) (5)








Natural gas (Mcfd)

693



175


Oil (Bpd)

3,535



1,538


Natural gas liquids (Bpd)

421



173


Total (Mcfed)

24,433



10,438


Mississippi Lime/Hunton:








Natural gas (Mcfd)

8,339


5,269


6,810


4,873

Oil (Bpd)

599


252


427


171

Natural gas liquids (Bpd)

669


432


561


322

Total (Mcfed)

15,948


9,374


12,734


7,834

Other Operating Areas:(4)








Natural gas (Mcfd)

3,152


3,922


3,253


4,408

Oil (Bpd)

27


16


25


18

Natural gas liquids (Bpd)

310


333


330


378

Total (Mcfed)

5,177


6,018


5,384


6,786

Total Production:(3)(5)








Natural gas (Mcfd)

228,258


229,931


226,526


158,886

Oil (Bpd)

5,440


1,413


3,436


1,329

Natural gas liquids (Bpd)

4,040


3,569


3,802


3,473

Total (Mcfed)

285,139


259,821


269,958


187,701









Average sales prices: (3)








Natural gas (per Mcf) (6)

$           3.66


$           3.63


$           3.76


$           3.47

Oil (per Bbl)(7)

$         84.81


$         90.51


$         87.76


$         91.01

Natural gas liquids (per Bbl) (8)

$         26.97


$         30.72


$         29.59


$         28.71









Production costs:(3)(9)








        Lease operating expenses per Mcfe

$           1.34


$           1.03


$           1.29


$           1.09

Production taxes per Mcfe

0.28


0.18


0.27


0.18

Transportation and compression expenses per Mcfe

0.22


0.28


0.25


0.24

Total production costs per Mcfe

$           1.84


$           1.49


$           1.81


$           1.50









Depletion per Mcfe(3)

$           2.28


$           2.07


$           2.27


$           1.89











(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)

Volumetric production per day for Rangely/Eagle Ford for the year ended December 31, 2014 includes


Rangely production from July 1, 2014, the date of the acquisition, through December 31, 2014; Eagle Ford includes production from November 5, 2014, the date of the acquisition, through December 31, 2014. Production per day for Rangely/Eagle Ford and total production per day represents total production volume over the 92 and 365 days within the three months and year ended December 31, 2014, respectively.



(6)

ARP's average sales prices for natural gas before the effects of financial hedging were $3.51 per Mcf


and $3.35 per Mcf for the three months ended December 31, 2014 and 2013, respectively, and $3.93 per Mcf and $3.25 per Mcf for the year ended December 31, 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 $3.61 per Mcf ($3.46 per Mcf before the effects of financial hedging) and $3.38 per Mcf ($3.10 per Mcf before the effects of financial hedging) for the three months ended December 31, 2014 and 2013, respectively, and $3.66 per Mcf ($3.84 per Mcf before the effects of financial hedging) and $3.21 per Mcf ($2.99 per Mcf before the effects of financial hedging) for the years ended December 31, 2014 and 2013, respectively.



(7)

ARP's average sales prices for oil before the effects of financial hedging were $65.29 per barrel and


$94.17 per barrel for the three months ended December 31, 2014 and 2013, respectively, and $82.22 per barrel and $95.88 per barrel for the years ended December 31, 2014 and 2013, respectively.



(8)

ARP's average sales prices for natural gas liquids before the effects of financial hedging were $21.80


per barrel and $32.04 per barrel for the three months ended December 31, 2014 and 2013, respectively, and $29.39 per barrel and $29.43 per barrel for the years ended December 31, 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 $1.32 per Mcfe ($1.82 per Mcfe for total production costs) and $0.94 per Mcfe ($1.40 per Mcfe for total production costs) for the three months ended December 31, 2014 and 2013, respectively, and $1.27 per Mcfe ($1.79 per Mcfe for total production costs) and $1.01 per Mcfe ($1.42 per Mcfe for total production costs) for the years ended December 31, 2014 and 2013, respectively.

 

 

 

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)



December 31,

2014


December 31,

2013

Total debt

$     1,394,460


$         942,334

Less:  Cash

(15,247)


(1,828)

Total net debt/(cash)

1,379,213


940,506





Partners' capital  

885,496


1,067,291





Total capitalization

$     2,264,709


$     2,007,797





Ratio of net debt to capitalization

0.61x


0.47x

 

 


ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)



Three Months Ended


Years Ended


December 31,


December 31,


2014


2013


2014


2013

Maintenance capital expenditures(1)

$    19,000


$    10,500


$    65,300


$    31,500

Expansion capital expenditures

43,149


49,041


147,334


232,037

        Total

$    62,149


$    59,541


$  212,634


$  263,537









(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


Years Ended


December 31,


December 31,

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

2014


2013


2014


2013

Net loss

$     (580,751)


$       (39,995)


$     (610,958)


$       (91,245)

Acquisition and related costs

5,049


4,026


17,814


29,923

Depreciation, depletion and amortization

62,641


51,702


233,731


136,763

Asset impairment

573,774


38,014


573,774


38,014

Amortization of deferred finance costs

3,155


1,007


9,445


9,649

Non-cash stock compensation expense

1,725


2,471


8,067


12,679

Maintenance capital expenditures(2)

(16,300)


(10,500)


(50,550)


(28,167)

Preferred unit distribution

(4,707)


(4,400)


(18,005)


(12,677)

Loss (gain) on asset sales and disposal

183


(1,048)


1,869


987

Premiums paid on swaption derivative contracts associated

  with asset acquisitions(3)

 


 


 


 

14,617

Non-cash valuation allowance

1,590



1,590


Unrealized gain on mark-to-market derivatives

(2,819)



(2,819)


Other

(188)


53


(204)


53

Distributable cash flow attributable to limited partners

  and the general partner(1)

 

$        43,352


 

$        41,330


 

$      163,754


 

$      110,596









Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:





Gas and oil production margin

$        80,544


$        59,726


$      277,763


$      169,546

Well construction and completion margin

6,085


9,860


22,639


21,898

Administration and oversight margin

3,492


3,354


15,564


12,277

Well services margin

4,036


2,283


14,952


9,977

Gathering and processing margin

(805)


(208)


(1,418)


(2,336)

Cash general and administrative expenses(4)

(13,091)


(7,799)


(44,878)


(35,461)

Other, net

59


186


386


214

Adjusted EBITDA(1)

80,320


67,402


285,008


176,115

Cash interest expense(5)

(15,961)


(11,172)


(52,699)


(24,675)

Preferred unit distribution

(4,707)


(4,400)


(18,005)


(12,677)

Maintenance capital expenditures(2)

(16,300)


(10,500)


(50,550)


(28,167)

Distributable Cash Flow attributable to limited partners

  and the general partner(1)

 

$        43,352


 

$        41,330


 

$      163,754


 

$      110,596









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)

 

3,757


 


 

33,959


 

25,791

Well construction and completion margin earned(7)


(4,760)



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

 

$        47,109


 

$        36,570


 

$      197,713


 

$      136,387









Distributions Paid(9)

$        53,729


$        37,381


$      198,740


$      130,464

  per limited partner unit

$        0.590


$        0.580


$        2.343


$        2.190









Excess (shortfall) of distributable cash flow with

  discretionary adjustments by the Board of Directors of the

  General Partner after distributions to unitholders(10)

 

 

$         (6,620)


 

 

$            (811)


 

 

$         (1,027)


 

 

$          5,923









(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)

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 three months ended December 31, 2014, such amounts include net cash generated by the Eagle Ford assets from October 1, 2014 to November 4, 2014 of $6.8 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.7 million. For the year ended December 31, 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 November 4, 2014 of $53.2 million, less pro forma interest expense of $2.8 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $14.7 million. For the year ended December 31, 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 three months ended September 30, 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 $87.1 million and $62.6 million for the three months ended December 31, 2014 and 2013, respectively, and $338.2 million and $208.6 million for the years ended December 31, 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. 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 March 2, 2015)







Natural Gas












Fixed Price Swaps








Average




Production Period


Fixed Price


Volumes


Ended December 31,


(per mmbtu)(a)


(mmbtus)(a)








2015


$    4.23


54,834,492


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


$    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)










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)






2015


$    (0.0821)


5,250,000






Crude Oil










Fixed Price Swaps







Average



Production Period


Fixed Price


Volumes

Ended December 31,


(per bbl)(a)


(bbls)(a)






2015


$    88.31


1,878,000

2016


$    83.50


1,425,000

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


$    83.85


$  110.65


29,250








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






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


$    1.0161


192,000

 

Mt Belvieu Butane Swaps







Average



Production Period


Fixed Price


Volumes

Ended December 31,


(per gallon)


(bbls)(a)






2015


$    1.2481


36,000


 

Mt Belvieu Iso-Butane Swaps







Average



Production Period


Fixed Price


Volumes

Ended December 31,


(per gallon)


(bbls)(a)






2015


$    1.2631


36,000


 

Mt Belvieu Natural Gasoline Swaps







Average



Production Period


Fixed Price


Volumes

Ended December 31,


(per gallon)


(bbls)(a)






2015


$    1.9831


120,000

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/atlas-resource-partners-lp-reports-operating-and-financial-results-for-the-fourth-quarter-and-full-year-2014-300043327.html

SOURCE Atlas Resource Partners, L.P.

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