2014

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

PITTSBURGH, May 7, 2014 /PRNewswire/ -- 

  • 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

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.

 

(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 7 to the Financial Information table of this release.

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,


December 31,

ASSETS


2014


2013

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,

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

2014


2013

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










Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per mmbtu)(a)


(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










Average


Average




Production Period


Floor Price


Ceiling Price


Volumes


Ended December 31,


(per mmbtu)(a)


(per mmbtu)(a)


(mmbtus)(a)










   2014(b)


$    4.22


$    5.12


2,880,000


2015


$    4.23


$    5.13


3,480,000










Put Options – Drilling
Partnerships










Average


Average




Production Period


Fixed Price


Volumes




Ended December 31,


(per mmbtu)(a)


(mmbtus)(a)












   2014(b)


$    3.80


1,350,000




2015


$    4.00


1,440,000




2016


$    4.15


1,440,000












WAHA Basis Swaps










Average


Average




Production Period


Fixed Price


Volumes




Ended December 31,


(per mmbtu)(a)


(mmbtus)(a)












   2014(b)


$    (0.110)


8,100,000



















Natural Gas Liquids








Crude Oil Fixed Price Swaps








Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per bbl)(a)


(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








Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per gallon)


(bbls)(a)












   2014(b)


$    0.3025


45,000




















Mt Belvieu Propane Swaps








Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per gallon)


(bbls)(a)




















   2014(b)


$    0.9996


220,500




2015


$    1.0161


192,000










Mt Belvieu Butane Swaps








Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per gallon)


(bbls)(a)












   2014(b)


$    1.3075


27,000




2015


$    1.2481


36,000









Mt Belvieu Iso-Butane Swaps








Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per gallon)


(bbls)(a)












   2014(b)


$    1.3225


27,000




2015


$    1.2631


36,000




Crude Oil










Fixed Price Swaps










Average






Production Period


Fixed Price


Volumes




Ended December 31,


(per bbl)(a)


(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










Average


Average




Production Period


Floor Price


Ceiling Price


Volumes


Ended December 31,


(per bbl)(a)


(per bbl)(a)


(bbls)(a)










   2014(b)


$    84.17


$  113.31


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.

 

SOURCE Atlas Resource Partners, L.P.



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