EX-99.1 2 d726047dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

NEWS RELEASE

 

CONTACT:     Brian J. Begley
    Vice President - Investor Relations
    Atlas Resource Partners, L.P.
    (877) 280-2857
    (215) 405-2718 (fax)
       

ATLAS RESOURCE PARTNERS, L.P. REPORTS OPERATING AND

FINANCIAL RESULTS FOR THE FIRST QUARTER 2014

 

  •   Atlas Resource Partners, L.P. (ARP) to acquire approximately 47 MMboe of mature low-decline oil and liquids reserves in northwest Colorado for $420 million

 

  •   The acquisition provides stable, high margin cash flow, low-decline production, as well as potential valuable development opportunities in the position

 

  •   The transaction will be immediately accretive on a fully financed basis to distributable cash flow per unit

 

  •   The acquisition of GeoMet natural gas properties in West Virginia was recently approved by GeoMet shareholders

 

  •   ARP’s development activities in the liquids rich Mississippi Lime and Marble Falls plays continue to yield significant levels of oil and liquids production

 

  •   Adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, increased to $64.5 million(1) for the first quarter 2014

 

  •   First quarter 2014 financial and operational results to be discussed on a conference call at 9AM ET on Thursday, May 8th

Pittsburgh, PA – May 7, 2014 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) has reported operating and financial results for the first quarter 2014.

Matthew A. Jones, President of ARP, said, “This quarter highlights the diligence and expertise of our company’s operating teams as we were able to withstand one of the most challenging winter seasons on record and move forward with our development activities particularly in our liquids rich development areas. As a result, our company’s net oil production has increased by approximately 15 percent in the first five weeks of the second quarter, our current quarter, compared to the first quarter average, and we anticipate further growth. Entirely through the organic development of our liquids rich assets, we’ve grown our net oil production by more than 60 percent since the first quarter of 2013. Lastly, our recently announced acquisition of oil properties in Colorado is a tremendous addition to our existing asset portfolio, providing to us stable cash flow and high production margins, and we look forward to additional opportunities to expand our business.”

*  *  *

 

  •   First quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $64.5 million(1), compared to $62.6 million for the fourth quarter 2013, and $31.4 million for the prior year comparable quarter. Results during the quarter were adversely impacted by approximately $3.5 million due to constrained production volumes caused by severe winter weather conditions.

 

  •  

Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $42.3 million(1), or $0.53 per common unit, for the first quarter 2014, compared to $41.0 million for the fourth quarter 2013 and $25.1 million for the prior year comparable quarter. Distributable Cash Flow with discretionary adjustments by the Board of

 

Directors of the General Partner was unfavorably impacted during the quarter by approximately $3.5 million, or $0.05 per unit, due to weather-related issues mentioned above. ARP’s first quarter 2014 cash distribution coverage would have been approximately 1.0x inclusive of the weather impact.

 

  •   ARP paid monthly cash distributions totaling $0.58 per limited partner unit for the first quarter 2014, an approximate 14% increase over the prior year first quarter distribution. The most recent ARP distribution for the month of March 2014 will be paid on May 15, 2014 to holders of record as of May 7, 2014.

 

  •   On a GAAP basis, net loss was $10.8 million for the first quarter 2014 compared to a net loss of $5.4 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, specifically depreciation, depletion and amortization in the current period from the larger amount of producing oil & gas assets compared to the prior year period.

Rangely Field Acquisition of Oil Properties in Colorado

On May 7, 2014, ARP announced that it entered into a definitive agreement to acquire total reserves of approximately 47 million barrels of oil equivalent (“Mmboe”) of oil and natural gas liquids (“NGLs”), including proved developed producing reserves of approximately 25 Mmboe, for $420 million. The acquired position is located in the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production. The transaction is subject to customary purchase price adjustments and is expected to close in the second quarter 2014, with an effective date of April 1, 2014. The assets generated net production of approximately 2,900 million barrels of oil equivalents (“Mmboed”) in the first quarter 2014.

The acquired assets are expected to provide ARP with a stable, high margin cash flow stream with a low-decline profile (average 3-4% annual decline rate over the past 15 years). The asset position is a tertiary oil recovery project using CO2 flood activity, and the production mix is predominantly oil at 90%, with the remainder coming from NGLs. ARP will have an approximate 25% non-operating net working interest in the assets, and Chevron Corporation will continue as operator. Material capital expenditures and growth projects are subject to ARP’s approval.

Approval of GeoMet Transaction

On February 14, 2014, ARP announced that it entered into a definitive agreement to acquire approximately 70 Bcfe of natural gas proved reserves in West Virginia and Virginia from GeoMet, Inc. (OTCQB: GMET) and certain of its subsidiaries (collectively, “GeoMet”) for $107 million, subject to customary adjustments, with an effective date of January 1, 2014. On May 5, 2014, the transaction was approved by a majority vote of GeoMet’s shareholders, and the transaction is expected to close in May 2014.

ARP expects to benefit from the mature, low-decline production from the acquired assets, which will complement the company’s existing oil and gas base. The assets consist of approximately 70 Bcfe of proved reserves in West Virginia and Virginia, and are 100% natural gas and proved developed.

E&P Operating Highlights

 

  •  

Average net daily production for the first quarter 2014 was 246.6 Mmcfed, an increase of approximately 85% from the prior year comparable quarter and a decrease of approximately 5% from the fourth quarter 2013. The sequential decrease in production was due to the adverse impact from winter weather during the first quarter 2014. During much of the period, the weather impact affected the ability to service producing wells, namely in the Mid-Continent region, and also delayed the connection of newly completed wells into sales lines. As a result, oil and gas production from certain areas was restricted for periods of time, which directly affected realized production margin for the first quarter 2014. ARP has estimated the impact was approximately

 

$3.5 million to Adjusted EBITDA from weather-related issues in the quarter. The increase in net production from the first quarter 2013 was due primarily to the acquisition of producing assets from EP Energy in July 2013, located in the Raton Basin (New Mexico), Black Warrior Basin (Alabama) and County Line region (Wyoming).

 

  •   ARP’s realized price for natural gas across all of its regions, excluding the effect of financial hedges, was $4.68 per per thousand cubic feet (“mcf”) in the first quarter 2014, compared to $3.35 per mcf in the fourth quarter 2013, a sequential increase of approximately 40%. Net realized natural gas prices including the effect of hedge positions was $4.07 per mcf for the current period, an increase of $0.44, or 12%, from the fourth quarter 2013.

Hedge Positions

 

  •   ARP continued to expand its commodity hedge positions on its existing production during the first quarter 2014. A summary of ARP’s derivative positions as of May 7, 2014 is provided in the financial tables of this release.

Corporate Expenses & Capital Position

 

  •   Cash general and administrative expense was $11.7 million for the first quarter 2014, $3.9 million higher than the fourth quarter 2013 and $2.1 million higher compared with the prior year first quarter. The increase compared with the fourth quarter 2013 was due primarily to certain administrative and marketing costs associated with ARP’s 2013 partnership program that were able to capitalized in the prior quarter. ARP capitalizes certain amounts of its general and administrative costs associated with the partnership programs as a component of its capital contributions to the partnership programs. The increase in expense compared with the prior year first quarter was principally due to larger operations stemming from ARP’s expanded asset position.

 

  •   Cash interest expense was $11.4 million for the first quarter 2014, consistent with the fourth quarter 2013 and $9.1 million higher than the prior year first quarter. The increase compared with the prior year quarter was primarily due to higher levels of borrowing used to expand ARP’s operations over the last year.

 

  •   As of March 31, 2014, ARP had $889 million of total debt, including $366 million outstanding under its revolving credit facility. ARP had approximately $365 million available on its revolving credit facility as of the end of the first quarter 2014.

*  *  *

Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.’s first quarter 2014 results on Thursday, May 8, 2014 at 9:00 am ET 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 1:00 p.m. ET on May 8, 2014 by dialing 855-859-2056, passcode: 30755727.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 13,000 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM) and Black Warrior Basin (AL). 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, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 34% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 15 active gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. For more information, visit the Partnership’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

*  *  *

Cautionary Note Regarding Forward-Looking Statements

This press release 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 and production 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 close the GeoMet acquisition, on the terms described or at all; ARP’s ability to obtain required consents in order to permit the transfer of the assets included in the GeoMet acquisition; ARP’s ability to obtain the required financing for the GeoMet acquisition, on desirable terms or at all; ARP’s ability to realize the anticipated benefits of the GeoMet transaction; changes in commodity prices and hedge positions; changes in the estimates of maintenance capital expense; 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, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except per unit data)

 

     Three Months Ended  
     March 31,  
     2014     2013  

Revenues:

     

Gas and oil production

    $ 96,245      $ 46,064   

Well construction and completion

      49,377        56,478   

Gathering and processing

      4,468        3,585   

Administration and oversight

      1,729        1,085   

Well services

      5,479        4,816   

Other, net

      47        20   
  

 

 

    

 

 

  

Total revenues

      157,345        112,048   
  

 

 

    

 

 

  

Costs and expenses:

     

Gas and oil production

      36,792        15,216   

Well construction and completion

      42,936        49,112   

Gathering and processing

      4,413        4,413   

Well services

      2,482        2,318   

General and administrative

      16,455        17,567   

Depreciation, depletion and amortization

      50,237        21,208   
  

 

 

    

 

 

  

Total costs and expenses

      153,315        109,834   
  

 

 

    

 

 

  

Operating income

      4,030        2,214   

Loss on asset sales and disposal

      (1,603 )      (702 ) 

Interest expense

      (13,188 )      (6,889 ) 
  

 

 

    

 

 

  

Net loss

      (10,761 )      (5,377 ) 

Preferred limited partner dividends

      (4,399 )      (1,957 ) 
  

 

 

    

 

 

  

Net loss attributable to common limited partners and the general partner

    $ (15,160 )    $ (7,334 ) 
  

 

 

    

 

 

  

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

     

General partner’s interest

    $ 2,004      $ 301   

Common limited partners’ interest

      (17,164 )      (7,635 ) 
  

 

 

    

 

 

  

Net loss attributable to common limited partners and the general partner

    $ (15,160 )    $ (7,334 ) 
  

 

 

    

 

 

  

Net loss attributable to common limited partners per unit:

     

Basic and Diluted

    $ (0.28 )    $ (0.17 ) 
  

 

 

    

 

 

  

Weighted average common limited partner units outstanding:

     

Basic and Diluted

      61,219        43,974   
  

 

 

    

 

 

  

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)

 

     March 31,
2014		      December 31,
2013		  
ASSETS      

Current assets:

      

Cash and cash equivalents

    $ 1,965       $ 1,828   

Accounts receivable

      78,127         58,822   

Current portion of derivative asset

      161         1,891   

Subscriptions receivable

      —           47,692   

Prepaid expenses and other

      17,481         10,097   
  

 

 

     

 

 

  

Total current assets

      97,734         120,330   

Property, plant and equipment, net

      2,125,189         2,120,818   

Goodwill and intangible assets, net

      32,679         32,747   

Long-term derivative asset

      23,749         27,084   

Other assets, net

      42,554         42,821   
  

 

 

     

 

 

  
   $ 2,321,905       $ 2,343,800   
  

 

 

     

 

 

  
LIABILITIES AND PARTNERS’ CAPITAL      

Current liabilities:

      

Accounts payable

    $ 94,472       $ 69,346   

Advances from affiliates

      24,413         26,742   

Liabilities associated with drilling contracts

      —           49,377   

Current portion of derivative liability

      22,372         6,353   

Accrued well drilling and completion costs

      66,199         40,481   

Accrued liabilities

      38,961         51,416   
  

 

 

     

 

 

  

Total current liabilities

      246,417         243,715   

Long-term debt

      889,388         942,334   

Asset retirement obligations and other

      92,110         90,460   

Commitments and contingencies

      

Partners’ Capital:

      

General partner’s interest

      1,485         4,482   

Preferred limited partners’ interests

      180,543         183,477   

Common limited partners’ interests

      905,888         852,457   

Class C preferred limited partner warrants

      1,176         1,176   

Accumulated other comprehensive income

      4,898         25,699   
  

 

 

     

 

 

  

Total partners’ capital

      1,093,990         1,067,291   
  

 

 

     

 

 

  
   $ 2,321,905       $ 2,343,800   
  

 

 

     

 

 

  

ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)

 

     Three Months Ended
March 31,		  
     2014     2013  

Net loss attributable to common limited partners per unit - basic

    $ (0.28 )    $ (0.17 ) 

Cash distributions paid per unit(1)

    $ 0.58      $ 0.51   

Production revenues (in thousands):

     

Natural gas

    $ 74,190      $ 29,056   

Oil

      12,283        8,806   

Natural gas liquids

      9,772        8,202   
  

 

 

    

 

 

  

Total production revenues

    $ 96,245      $ 46,064   
  

 

 

    

 

 

  

Production volume:(2)(3)

     

Appalachia: (4)

     

Natural gas (Mcfd)

      41,146        31,568   

Oil (Bpd)

      415        278   

Natural gas liquids (Bpd)

      29        2   
  

 

 

    

 

 

  

Total (Mcfed)

      43,810        33,244   
  

 

 

    

 

 

  

Raton/Black Warrior: (4)

     

Natural gas (Mcfd)

      108,368        —     

Oil (Bpd)

      —          —     

Natural gas liquids (Bpd)

      —          —     
  

 

 

    

 

 

  

Total (Mcfed)

      108,368        —     
  

 

 

    

 

 

  

Barnett/Marble Falls:

     

Natural gas (Mcfd)

      57,898        66,069   

Oil (Bpd)

      834        780   

Natural gas liquids (Bpd)

      2,570        2,557   
  

 

 

    

 

 

  

Total (Mcfed)

      78,319        86,092   
  

 

 

    

 

 

  

Mississippi Lime/Hunton:

     

Natural gas (Mcfd)

      5,873        4,757   

Oil (Bpd)

      301        29   

Natural gas liquids (Bpd)

      485        243   
  

 

 

    

 

 

  

Total (Mcfed)

      10,587        6,393   
  

 

 

    

 

 

  

Other Operating Areas: (4)

     

Natural gas (Mcfd)

      3,402        4,861   

Oil (Bpd)

      19        14   

Natural gas liquids (Bpd)

      338        394   
  

 

 

    

 

 

  

Total (Mcfed)

      5,544        7,311   
  

 

 

    

 

 

  

Total Production: (3)

     

Natural gas (Mcfd)

      216,688        107,255   

Oil (Bpd)

      1,568        1,101   

Natural gas liquids (Bpd)

      3,422        3,197   
  

 

 

    

 

 

  

Total (Mcfed)

      246,628        133,039   
  

 

 

    

 

 

  

Average sales prices: (3)

     

Natural gas (per Mcf) (5)

    $ 4.07      $ 3.33   

Oil (per Bbl)(6)

    $ 87.04      $ 88.89   

Natural gas liquids (per Bbl) (7)

    $ 31.73      $ 28.51   

Production costs:(3)(8)

     

Lease operating expenses per Mcfe

    $ 1.17      $ 0.97   

Production taxes per Mcfe

      0.27        0.22   

Transportation and compression expenses per Mcfe

      0.29        0.16   
  

 

 

    

 

 

  

Total production costs per Mcfe

    $ 1.73      $ 1.35   

Depletion per Mcfe(3)

    $ 2.16      $ 1.64   

 

 

(1)  Represents the cash distributions declared per limited partner unit for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.
(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; Raton/Black Warrior includes ARP’s production located in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama; 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 $4.68 per Mcf and $2.90 per Mcf for the three months ended March 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 $3.80 per Mcf ($4.42 per Mcf before the effects of financial hedging) and $3.01 per Mcf ($2.59 per Mcf before the effects of financial hedging) for the three months ended March 31, 2014 and 2013, respectively.
(6)  ARP’s average sales prices for oil before the effects of financial hedging were $93.18 per barrel and $90.80 per barrel for the three months ended March 31, 2014 and 2013, respectively.
(7)  ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $35.65 per barrel and $28.74 per barrel for the three months ended March 31, 2014 and 2013, 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 $1.10 per Mcfe ($1.66 per Mcfe for total production costs) and $0.90 per Mcfe ($1.27 per Mcfe for total production costs) for the three months ended March 31, 2014 and 2013, respectively.

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

(unaudited; in thousands)

 

     March 31,
2014		     December 31,
2013		  

Total debt

    $ 889,388      $ 942,334   

Less: Cash

      (1,965 )      (1,828 ) 
  

 

 

    

 

 

  

Total net debt/(cash)

      887,423        940,506   

Partners’ capital

      1,093,990        1,067,291   
  

 

 

    

 

 

  

Total capitalization

    $ 1,981,413      $ 2,007,797   
  

 

 

    

 

 

  

Ratio of net debt to capitalization

      0.45x        0.47x   

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

(unaudited; in thousands)

 

     Three Months Ended
March 31,		  
     2014      2013  

Maintenance capital expenditures (1)

    $ 10,800       $ 4,000   

Expansion capital expenditures

      29,097         54,487   
  

 

 

     

 

 

  

Total

    $ 39,897       $ 58,487   
  

 

 

     

 

 

  

 

(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,		  
     2014     2013  

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

     

Net loss

    $ (10,761 )    $ (5,377 ) 

Acquisition and related costs

      2,379        3,714   

Depreciation, depletion and amortization

      50,237        21,208   

Amortization of deferred finance costs

      1,812        4,642   

Non-cash stock compensation expense

      2,345        4,247   

Maintenance capital expenditures(2)

      (10,800 )      (4,000 ) 

Loss on asset sales and disposal

      1,603        702   

Other

      (3 )      —     
  

 

 

    

 

 

  

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

    $ 36,812      $ 25,136   
  

 

 

    

 

 

  

Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:

     

Gas and oil production margin

    $ 59,453      $ 30,848   

Well construction and completion margin

      6,441        7,366   

Administration and oversight margin

      1,729        1,085   

Well services margin

      2,997        2,498   

Gathering

      55        (828 ) 

Cash general and administrative expenses(3)

      (11,731 )      (9,606 ) 

Other, net

      44        20   
  

 

 

    

 

 

  

Adjusted EBITDA(1)

      58,988        31,383   

Cash interest expense(4)

      (11,376 )      (2,247 ) 

Maintenance capital expenditures(2)

      (10,500 )      (4,000 ) 
  

 

 

    

 

 

  

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

    $ 37,112      $ 25,136   
  

 

 

    

 

 

  

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(5)

      5,197        —     
  

 

 

    

 

 

  

Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(6)

    $ 42,309      $ 25,136   
  

 

 

    

 

 

  

Distributions Paid(7)

    $ 45,731      $ 25,330   

per limited partner unit

    $ 0.58      $ 0.51   

Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(8)

    $ (3,422 )    $ (194 ) 

 

(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)  Excludes non-cash stock compensation expense and certain acquisition and related costs.
(4)  Excludes non-cash amortization of deferred financing costs.
(5)  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 1st quarter 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.

(6)  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.
(7)  Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.
(8)  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 May 7, 2014)

Natural Gas

 

Fixed Price Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per mmbtu)(a)		      Volumes
(mmbtus)(a)		  

2014(b)

    $ 4.15         45,114,732   

2015

    $ 4.24         51,924,492   

2016

    $ 4.31         45,746,320   

2017

    $ 4.53         24,840,000   

2018

    $ 4.72         3,960,000   

 

Costless Collars

                     

Production Period Ended December 31,

    Average
Floor Price
(per mmbtu)(a)		      Average
Ceiling Price
(per mmbtu)(a)		      Volumes
(mmbtus)(a)		  

2014(b)

    $ 4.22       $ 5.12         2,880,000   

2015

    $ 4.23       $ 5.13         3,480,000   

 

Put Options – Drilling Partnerships

              

Production Period Ended December 31,

    Average
Fixed Price
(per mmbtu)(a)		      Average
Volumes
(mmbtus)(a)		  

2014(b)

    $ 3.80         1,350,000   

2015

    $ 4.00         1,440,000   

2016

    $ 4.15         1,440,000   

 

WAHA Basis Swaps

             

Production Period Ended December 31,

    Average
Fixed Price
(per mmbtu)(a)		     Average
Volumes
(mmbtus)(a)		  

2014(b)

    $ (0.110 )      8,100,000   

Natural Gas Liquids

 

Crude Oil Fixed Price Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per bbl)(a)		      Volumes
(bbls)(a)		  

2014(b)

    $ 91.57         79,500   

2015

    $ 88.55         96,000   

2016

    $ 85.65         84,000   

2017

    $ 83.78         60,000   

Mt Belvieu Ethane Purity Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per gallon)		      Volumes
(bbls)(a)		  

2014(b)

    $ 0.3025         45,000   

Mt Belvieu Propane Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per gallon)		      Volumes
(bbls)(a)		  

2014(b)

    $ 0.9996         220,500   

2015

    $ 1.0161         192,000   

Mt Belvieu Butane Swaps

  

Production Period Ended December 31,

    Average
Fixed Price
(per gallon)		      Volumes
(bbls)(a)		  

2014(b)

    $ 1.3075         27,000   

2015

    $ 1.2481         36,000   

Mt Belvieu Iso-Butane Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per gallon)		      Volumes
(bbls)(a)		  

2014(b)

    $ 1.3225         27,000   

2015

    $ 1.2631         36,000   

Crude Oil

 

Fixed Price Swaps

              

Production Period Ended December 31,

    Average
Fixed Price
(per bbl)(a)		      Volumes
(bbls)(a)		  

2014(b)

    $ 92.69         409,500   

2015

    $ 88.14         567,000   

2016

    $ 85.52         225,000   

2017

    $ 83.30         132,000   

 

Costless Collars

                     

Production Period Ended December 31,

    Average
Floor Price
(per bbl)(a)		      Average
Ceiling Price
(per bbl)(a)		      Volumes
(bbls)(a)		  

2014(b)

    $ 84.17       $ 113.31         30,870   

2015

    $ 83.85       $ 110.65         29,250   

 

(a)  “mmbtu” represents million metric British thermal units.; “bbl” represents barrel.
(b)  Reflects hedges covering the last nine months of 2014.