Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) has reported operating and financial results for the fourth quarter and full year 2013.

Matthew A. Jones, President of ARP, said, “This quarter represented strong progress across the entire scope of our operations. In particular, we experienced improved results in our Mississippi Lime position, and continue to see better than expected results from the mature production of our Raton and Black Warrior assets. Our experienced and highly skilled operating team performed admirably in advancing our business despite extremely harsh winter weather conditions. We remain focused on increasing cash flow for our unitholders through acquisitions and organic growth.”
  • ARP generated Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, of $62.6 million(1) for the fourth quarter 2013, compared to $60.7 million for the third quarter 2013, and $31.8 million for the prior year comparable quarter. Fourth quarter 2013 Adjusted EBITDA was unfavorably impacted by approximately $2.5 million to $3.0 million due to lower volumes in its Barnett Shale and Marble Falls regions caused by adverse weather conditions which occurred in those regions. Adjusted EBITDA was $208.6 million for the full year 2013, compared to $84.5 million for the full year 2012.
  • Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $41.0 million(1), or $0.58 per common unit, for the fourth quarter 2013, compared to $27.5 million for the prior year comparable quarter, and $149.1 million for the full year 2013, compared to $64.1 million for the full year 2012. Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner was unfavorably impacted by approximately $2.5 million to $3.0 million, or $0.02 to $0.03 per unit, due to weather-related impacts mentioned above. ARP would have covered its fourth quarter 2013 cash distribution by $1.7 million to $2.2 million, or approximately 1.05x, inclusive of the storm impact.
  • ARP declared a cash distribution of $0.58 per limited partner unit for the fourth quarter 2013, an approximate 4% increase, over the third quarter 2013 and a 21% increase from the prior year fourth quarter distribution. The fourth quarter 2013 ARP distribution was paid on February 14, 2014 to holders of record as of February 6, 2014.
  • ARP also declared its initial monthly distribution of $0.1933 per common unit for the month of January 2014 on February 24, 2014, which is payable on March 17, 2014 to holders of record as of March 7, 2014. ARP previously announced that its board of directors had approved the modification of its distribution payment practice to a monthly distribution program. ARP management and the board of directors determined that a monthly distribution policy more closely aligned the realization and distribution of cash flow with investors’ interests.
  • On a GAAP basis, net loss was $40.0 million for the fourth quarter 2013 compared to a net loss of $18.9 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, including depreciation, depletion and amortization, asset impairments and non-cash compensation expense. During the fourth quarter 2013, ARP recognized $38.0 million of asset impairments principally related to non-core oil and gas properties in the New Albany Shale (IN) and expiring acreage in its Chattanooga (TN) and New Albany Shale regions.

(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 11 to the Financial Information table on page 11 of this release.

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. The acquisition is expected to be immediately accretive to ARP’s distributable cash flow per unit. The transaction is subject to, among other items, approval from GeoMet’s stockholders.

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. Current net production on the assets is approximately 22 million cubic feet equivalents per day (“Mmcfed”) from over 400 active wells, with a current expected decline rate of approximately 10-12%. Current production costs include lease operating costs of approximately $1.20/mcf, production and ad valorem taxes of approximately 10%, and transportation and gathering costs of approximately $0.40 per thousand cubic feet (“mcf”).

Year End 2013 Oil & Gas Reserves

Throughout 2013, ARP substantially increased its oil & gas reserves and undeveloped properties through both strategic acquisitions as well as organic development. This activity, namely from the acquisition of producing natural gas assets in the Raton (NM) and Black Warrior (AL) Basins, as well as continued development in the Mississippi Lime and Marble Falls regions, resulted in a significant increase in ARP’s proved reserves as of year end 2013.

As of December 31, 2013, based on the SEC average price assumptions of $3.67 per mcf for natural gas and $96.78 per barrel for crude oil, net proved oil and gas reserves were approximately 1.2 trillion cubic feet equivalents (“Tcfe”), an increase of approximately 61% from the year end 2012 reserve levels. The year end 2013 reserves were valued at a PV-10 amount of approximately $1.0 billion, which does not include the value of ARP’s commodity derivatives. The fair value of ARP’s commodity derivatives at December 31, 2013 was approximately $22.6 million. Approximately 68% of ARP’s reserves were proved developed, compared to 56% at the end of 2012.

E&P Operating Highlights
  • Average net daily production for the fourth quarter 2013 was 259.8 Mmcfed, an increase of approximately 97% from the prior year comparable quarter. The increase in net production from the fourth quarter 2012 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). Production also increased from additional wells connected in the fourth quarter 2013 in several of ARP’s key operating areas, including the Mississippi Lime and Marble Falls.
  • During 2013, ARP continued development on its acreage positions located in several attractive U.S. oil and natural gas basins. ARP turned into line the following number of gross wells per region during 2013: 82 wells in the Marble Falls/Barnett Shale region; 21 wells in the Mississippi Lime play in northwestern Oklahoma; 9 wells in the Marcellus Shale (8 of which were in Lycoming County, PA); and 5 wells in the Utica Shale Play in Harrison County, OH.
  • In the fourth quarter 2013, ARP experienced adverse weather conditions in several of its operating areas, namely in Texas. As a result, oil and gas production from certain areas was restricted for periods of time, which directly affected realized production margin for the fourth quarter 2013. ARP has estimated the impact was approximately $2.5 million to $3.0 million to Distributable Cash Flow from weather-related issues in the quarter.

Hedge Positions
  • ARP continued to expand its commodity hedge positions on its existing production during the fourth quarter 2013. A summary of ARP’s derivative positions as of February 27, 2014 is provided in the financial tables of this release.

Corporate Expenses & Capital Position
  • Cash general and administrative expense was $7.8 million for the fourth quarter 2013, $1.8 million lower than the third quarter 2013 and $1.2 million lower compared with the prior year fourth quarter. The decrease compared with the third quarter 2013 was due primarily due to a $2.5 million increase in the capitalization of administrative costs associated with ARP’s 2013 partnership program due to the increase in funds raised between periods. 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 decrease compared with the prior year fourth quarter was principally due to lower annual incentive compensation amounts recognized during the period.
  • Cash interest expense was $11.2 million for the fourth quarter 2013, an increase of $3.3 million compared with the third quarter 2013 and $10.3 million higher than the prior year fourth quarter. The increase compared with the third quarter 2013 was primarily due to a full quarter’s interest expense from the $250 million of 9.25% senior notes due 2021, which were issued in July 2013 and were used to partially finance the acquisition of natural gas assets from EP Energy in July 2013.
  • As of December 31, 2013, ARP had $942 million of total debt, including $419 million outstanding under its revolving credit facility. ARP had approximately $312 million available on its revolving credit facility as of the end of the fourth quarter.

Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.’s fourth quarter and full year 2013 results on Friday, February 28, 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 February 28, 2014 by dialing 888-286-8010, passcode: 19431975.

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 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 37% 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 14 active gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. 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 COMBINED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
       
Three Months Ended Years Ended
December 31, December 31,
2013     2012 2013     2012
Revenues:
Gas and oil production $ 93,293 $ 31,578 $ 266,783 $ 92,901
Well construction and completion 75,590 39,219 167,883 131,496
Gathering and processing 4,037 5,956 15,676 16,267
Administration and oversight 3,354 3,224 12,277 11,810
Well services 4,789 4,697 19,492 20,041
Other, net   133     66     (14,456 )   (4,886 )
Total revenues   181,196     84,740     467,655     267,629  
 
Costs and expenses:
Gas and oil production 33,567 10,377 97,237 26,624
Well construction and completion 65,730 34,197 145,985 114,079
Gathering and processing 4,245 6,306 18,012 19,491
Well services 2,506 2,204 9,515 9,280
General and administrative 14,296 20,696 78,063 69,123
Chevron transaction expense 7,670
Depreciation, depletion and amortization 51,702 18,734 136,763 52,582
Asset impairment   38,014     9,507     38,014     9,507  
Total costs and expenses   210,060     102,021     523,589     308,356  
 
Operating loss (28,864 ) (17,281 ) (55,934 ) (40,727 )
 
Gain (loss) on asset sales and disposal 1,048 39 (987 ) (6,980 )
Interest expense   (12,179 )   (1,666 )   (34,324 )   (4,195 )
 
Net loss (39,995 ) (18,908 ) (91,245 ) (51,902 )
 
Preferred limited partner dividends   (4,400 )   (1,842 )   (11,992 )   (3,063 )
Net loss attributable to owner’s interest, common limited partners and the general partner

$

(44,395

)

$

(20,750

)

$

(103,237

)

$

(54,965

)
 
Allocation of net loss:
Portion applicable to owner’s interest (period prior to the transfer of assets on March 5, 2012)

$

$

$

$ 250
Portion applicable to common limited partners and general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)  

 

(44,395

 

)
  (20,750 )  

 

(103,237

 

)
  (55,215 )
Net loss attributable to owner’s interest, common limited partners and the general partner $ (44,395 ) $ (20,750 ) $ (103,237 ) $ (54,965 )
 
Allocation of net loss attributable to common limited partners and the general partner:
General partner’s interest $ 1,209 $ (266 ) $ 3,344 $ (955 )
Common limited partners’ interest   (45,604 )   (20,484 )   (106,581 )   (54,260 )
Net loss attributable to common limited partners and the general partner $ (44,395 )

$

(20,750

)
$ (103,237 )

$

(55,215

)
 
Net loss attributable to common limited partners per unit:

Basic and Diluted
$ (0.77 ) $ (0.53 ) $ (2.03 ) $ (1.59 )
 
Weighted average common limited partner units outstanding:
Basic and Diluted   59,447     39,003     52,528     34,039  
 
 
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands)
   
December 31,

ASSETS
2013     2012
Current assets:
Cash and cash equivalents $ 1,828 $ 23,188
Accounts receivable 58,822 38,718
Current portion of derivative asset 1,891 12,274
Subscriptions receivable 47,692 55,357
Prepaid expenses and other   10,097   9,063
Total current assets 120,330 138,600
 
Property, plant and equipment, net 2,120,818 1,302,228
Goodwill and intangible assets, net 32,747 33,104
Long-term derivative asset 27,084 8,898
Long-term derivative receivable from Drilling Partnerships 863

Other assets, net
  41,958   16,122
$ 2,343,800 $ 1,498,952
 
LIABILITIES AND PARTNERS’ CAPITAL
 
Current liabilities:
Accounts payable $ 69,346 $ 59,549
Advances from affiliates 26,742 5,853
Liabilities associated with drilling contracts 49,377 67,293
Current portion of derivative liability 6,353
Current portion of derivative payable to Drilling Partnerships 2,676 11,293
Accrued well drilling and completion costs 40,481 47,637
Accrued liabilities   48,740   25,388
Total current liabilities 243,715 217,013
 
Long-term debt 942,334 351,425
Long-term derivative liability 67 888
Long-term derivative payable to Drilling Partnerships 2,429
Asset retirement obligations and other 90,393 65,191
 
Commitments and contingencies
 
Partners’ Capital:
General partner’s interest 4,482 7,029
Preferred limited partners’ interests 183,477 96,155
Common limited partners’ interests 852,457 737,253
Class C preferred limited partner warrants 1,176
Accumulated other comprehensive income   25,699   21,569
Total partners’ capital   1,067,291   862,006
$ 2,343,800 $ 1,498,952
 
 

ATLAS RESOURCE PARTNERS, L.P.

Financial and Operating Highlights

(unaudited)
       
Three Months Ended Years Ended
December 31, December 31,
2013     2012 2013     2012
 
Net loss attributable to common limited partners per unit - basic $ (0.77 ) $ (0.53 ) $ (2.03 ) $ (1.59 )
 
Cash distributions paid per unit(1) $ 0.58 $ 0.48 $ 2.19 $ 1.43
 
Production revenues (in thousands):
Natural gas $ 71,440 $ 22,362 $ 186,229 $ 70,151
Oil 11,766 3,732 44,160 11,351
Natural gas liquids   10,087     5,484     36,394     11,399  
Total production revenues $ 93,293   $ 31,578   $ 266,783   $ 92,901  
 
Production volume:(2)(3)

Appalachia: (4)
Natural gas (Mcfd) 45,768 34,134 36,705 33,889
Oil (Bpd) 452 291 332 278
Natural gas liquids (Bpd)   70     2     22     10  
Total (Mcfed)   48,904     35,892     38,825     35,618  

Raton/Black Warrior: (4)(5)
Natural gas (Mcfd) 113,346 47,848
Oil (Bpd)
Natural gas liquids (Bpd)                
Total (Mcfed)   113,346         47,848      

Barnett/Marble Falls: (6)
Natural gas (Mcfd) 61,625 61,323 65,053 28,855
Oil (Bpd) 692 784 808 28
Natural gas liquids (Bpd)   2,734     2,501     2,751     473  
Total (Mcfed)   82,179     81,032     86,409     31,861  

Mississippi Lime/Hunton: (7)
Natural gas (Mcfd) 5,269 4,895 4,873 1,392
Oil (Bpd) 252 31 171 8
Natural gas liquids (Bpd)   432     323     322     81  
Total (Mcfed)   9,374     7,017     7,834     1,926  

Other Operating Areas: (4)
Natural gas (Mcfd) 3,922 5,393 4,408 5,271
Oil (Bpd) 16 14 18 16
Natural gas liquids (Bpd)   (333 )   415     (378 )   410  
Total (Mcfed)   6,018     7,971     6,786     7,827  

Total Production: (3)(5)(6)(7)
Natural gas (Mcfd) 229,931 95,845 158,886 69,408
Oil (Bpd) 1,413 447 1,329 330
Natural gas liquids (Bpd)   3,569     1,935     3,473     974  
Total (Mcfed)   259,821     110,137     187,701     77,232  
 
Average sales prices: (3)
Natural gas (per Mcf) (8) $ 3.63 $ 3.04 $ 3.47 $ 3.29
Oil (per Bbl)(9) $ 90.51 $ 90.76 $ 91.01 $ 94.02
Natural gas liquids (per Bbl) $ 30.72 $ 30.80 $ 28.71 $ 31.97
 
Production costs:(3)(10)
Lease operating expenses per Mcfe $ 1.03 $ 0.88 $ 1.09 $ 0.82
Production taxes per Mcfe 0.18 0.14 0.18 0.12
Transportation and compression expenses per Mcfe   0.28     0.18     0.24     0.24  
Total production costs per Mcfe $ 1.49 $ 1.19 $ 1.50 $ 1.19
 
Depletion per Mcfe(3) $ 2.07 $ 1.71 $ 1.89 $ 1.66
 

(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. The cash distribution declared of $0.12 per limited partner unit for the 1st quarter 2012 reflects a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.
 

(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)

Volumetric production for Raton/Black Warrior for the year ended December 31, 2013 represents production for the 153-day period from the date of acquisition (July 31, 2013) through December 31, 2013 on a per day basis over the 365 days within the period.
 

(6)

Volumetric production for Barnett/Marble Falls for the three months ended December 31, 2012 represents production associated with the DTE assets for the 12-day period from December 20, 2012, the date of acquisition, through December 31, 2012 on a per day basis over the 12 days in that period. Volumetric production for Barnett/Marble Falls for the year ended December 31, 2012 represents production from the date of acquisition for DTE, Titan (July 25, 2012) and Carrizo (April 30, 2012) through December 31, 2012 on a per day basis over the 366 days within the period.
 

(7)

Volumetric production for Mississippi Lime/Hunton for the year ended December 31, 2013 represents production for the 99-day period from the date of acquisition (September 24, 2012) through December 31, 2013 on a per day basis over the 366 days within the period.
 

(8)

ARP’s average sales prices for natural gas before the effects of financial hedging were $3.35 per Mcf and $2.98 per Mcf for the three months ended December 31, 2013 and 2012, respectively, and $3.25 per Mcf and $2.60 per Mcf for the years ended December 31, 2013 and 2012, 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 $3.38 per Mcf ($3.10 per Mcf before the effects of financial hedging) and $2.54 per Mcf ($2.48 per Mcf before the effects of financial hedging) for the three months ended December 31, 2013 and 2012, respectively, and $3.21 per Mcf ($2.99 per Mcf before the effects of financial hedging) and $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) for the years ended December 31, 2013 and 2012, respectively.
 

(9)

ARP’s average sales prices for oil before the effects of financial hedging were $94.17 per barrel and $87.55 per barrel for the three months ended December 31, 2013 and 2012, respectively, and $95.88 per barrel and $91.32 per barrel for the years ended December 31, 2013 and 2012, respectively.
 

(10)

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 $0.94 per Mcfe ($1.40 per Mcfe for total production costs) and $0.71 per Mcfe ($1.02 per Mcfe for total production costs) for the three months ended December 31, 2013 and 2012, respectively, and $1.01 per Mcfe ($1.42 per Mcfe for total production costs) and $0.58 per Mcfe ($0.94 per Mcfe for total production costs) for the years ended December 31, 2013 and 2012, respectively.
 
 

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION
(unaudited; in thousands)
       
December 31, December 31,
2013 2012
Total debt $ 942,334 $ 351,425
Less: Cash   (1,828 )   (23,188 )
Total net debt/(cash) 940,506 328,237
 
Partners’ capital   1,067,291     862,006  
 
Total capitalization $ 2,007,797   $ 1,190,243  
 
Ratio of net debt to capitalization 0.47x 0.28x
 
 

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
       
Three Months Ended Years Ended
December 31, December 31,
2013     2012 2013     2012
Maintenance capital expenditures (1) $ 10,500 $ 3,350 $ 31,500 $ 10,200
Expansion capital expenditures   49,041   50,497   232,037   117,026
Total $ 59,541 $ 53,847 $ 263,537 $ 127,226
 
(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): 2013     2012 2013     2012
Net loss $ (39,995 ) $ (18,908 ) $ (91,245 ) $ (51,902 )
Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)(2)

 

 

 

 

(7,880

 

)
Acquisition and related costs 4,026 8,701 29,923 22,200
Depreciation, depletion and amortization 51,702 18,734 136,763 52,582
Asset impairment 38,014 9,507 38,014 9,507
Amortization of deferred finance costs 1,007 793 9,649 1,821
Non-cash stock compensation expense 2,471 2,972 12,679 10,833
Maintenance capital expenditures(3) (10,500 ) (3,050 ) (28,167 ) (9,300 )
Loss (gain) on asset sales and disposal (1,048 ) (39 ) 987 6,980
Chevron transaction expense(4) 7,670
Adjustment to reflect cash impact of derivatives(5) 4,518
Premiums paid on swaption derivative contracts associated with asset acquisitions(6)

14,480

5,001
Other   53         190      
Distributable cash flow attributable to limited partners and the general partner(1)(2)

$

45,730
 

$

18,710
 

$

123,273
 

$

52,030
 
 
Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Gas and oil production margin $ 59,726 $ 21,201 $ 169,546 $ 70,795
Well construction and completion margin 9,860 5,022 21,898 17,417
Administration and oversight margin 3,354 3,224 12,277 11,810
Well services margin 2,283 2,493 9,977 10,761
Gathering (208 ) (350 ) (2,336 ) (3,224 )
Cash general and administrative expenses(7) (7,799 ) (9,023 ) (35,461 ) (36,090 )
Other, net   186     66     214     115  
Adjusted EBITDA(1) 67,402 22,633 176,115 71,584
Cash interest expense(8) (11,172 ) (873 ) (24,675 ) (2,374 )
Maintenance capital expenditures(3)   (10,500 )   (3,050 )   (28,167 )   (9,300 )
Distributable Cash Flow(1) 45,730 18,710 123,273 59,910
Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)(1)(2)  

 

   

 

   

 

   

 

(7,880

 

)
Distributable Cash Flow attributable to limited partners and the general partner(1)(2)

$

45,730
 

$

18,710
 

$

123,273
 

$

52,030
 
 
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(9)

8,831

25,791

12,041
Well construction and completion margin earned(10)   (4,760 )            
Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(11)

$

40,970
 

$

27,541
 

$

149,064
 

$

64,071
 
 
Distributions Paid(12) $ 41,781 $ 23,567 $ 143,141 $ 57,441
per limited partner unit $ 0.58 $ 0.48 $ 2.19 $ 1.43
 
Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(14)

 

$

 

(811

 

)

 

$

 

3,974

 

$

 

5,923

 

$

 

6,630
 
(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)

In accordance with prevailing accounting literature, ARP has adjusted its historical financial statements to present them combined with the historical financial results of the spin-off assets for all periods prior to its spin-off date of March 5, 2012.
(3)

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.
(4)

Reflects a working capital adjustment recognized in September 2012 related to certain amounts included within the contractual cash transaction adjustment associated with the acquisition of certain natural gas and oil properties, the partnership management business, and other assets from AEI, the former owner of Atlas Energy’s general partner, in February 2011. Under GAAP, purchase accounting for an acquisition can be adjusted for up to twelve months after consummation of the transaction – any adjustments after the twelve month window must be treated as income or expense in an enterprise’s statement of operations. ARP excluded this item from Adjusted EBITDA and DCF for the purpose of evaluating DCF for the period to determine its quarterly cash distribution.
(5)

Includes $4.5 million of net cash proceeds received during the year ended December 31, 2012 related to the rebalancing of ARP’s hedge portfolio for production periods during 2015 and 2016. These amounts were not recognized within its statement of operations for the year ended December 31, 2012, but will be recognized as income during the 2015 and 2016 production periods the original derivatives were scheduled to be settled. ARP included this item in its determination of Adjusted EBITDA, DCF and cash distributions for the period presented, and will exclude the amount from its determination of such amounts for the 2015 and 2016 periods.
(6)

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.
(7)

Excludes non-cash stock compensation expense and certain acquisition and related costs.
(8)

Excludes non-cash amortization of deferred financing costs.
(9)

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 4th quarter 2012, such amounts include net cash generated by the DTE assets from October 1, 2012 to December 20, 2012 of $9.1 million, less estimated maintenance capital expenditures of $0.3 million. For the year ended December 31, 2013, such amounts include pro forma net cash generated by the EP Energy assets of $32.4 million from April 1, 2013 to July 31, 2013, less pro forma interest expense of $3.3 million and estimated maintenance capital expenditures of $3.3 million. For the year ended December 31, 2012, such amounts include net cash generated by the DTE assets from October 1, 2012 to December 20, 2012, Titan assets from July 1, 2012 to July 24, 2012, the Equal assets from July 1, 2012 to September 23, 2012, and the Carrizo assets from April 1, 2012 to April 29, 2012 of $12.9 million, less estimated maintenance capital expenditures of $0.9 million.
(10)

This amount reflects well construction and completion margin from the deployment of capital for the investment partnership programs during the 3rd quarter 2013 for which ARP was required to defer recognition under GAAP until additional investor funds were received. Under ARP’s annual investment partnership programs, investor funds must be received by the particular investment partnership by December 31st of that calendar year to be eligible for an investment in that program.
(11)

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 $62.6 million and $31.8 million for the three months ended December 31, 2013 and 2012, respectively, and $208.6 million and $84.5 million for the years ended December 31, 2013 and 2012, respectively.
(12)

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. The cash distribution declared of $0.12 per limited partner unit for the 1st quarter 2012 reflected a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.
(13)

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 February 27, 2014)
       

Natural Gas
 

Fixed Price Swaps
Average
Production Period Fixed Price Volumes
Ended December 31, (per mmbtu)(a) (mmbtus)(a)
 
2014 $ 4.15 60,152,976
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 $ 4.22 $ 5.12 3,840,000
2015 $ 4.23 $ 5.13 3,480,000
 

Natural Gas Liquids

 
 

Crude Oil Fixed Price Swaps

 
Average
Production Period Fixed Price Volumes
Ended December 31, (per bbl)(a) (bbls)(a)
 
2014 $ 91.57 105,000
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 $ 0.3025 60,000
 
 

Mt Belvieu Propane Swaps
Average
Production Period Fixed Price Volumes
Ended December 31, (per gallon) (bbls)(a)
 
 
2014 $ 0.9996 294,000
2015 $ 1.0161 192,000
 

Mt Belvieu Butane Swaps

 
Average
Production Period Fixed Price Volumes
Ended December 31, (per gallon) (bbls)(a)
 
2014 $ 1.3075 36,000
2015 $ 1.2481 36,000
 

Mt Belvieu Iso-Butane Swaps
Average
Production Period Fixed Price Volumes
Ended December 31, (per gallon) (bbls)(a)
 
2014 $ 1.3225 36,000
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 $ 92.67 552,000
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 $ 84.17 $ 113.31 41,160
2015 $ 83.85 $ 110.65 29,250
 

(a)
 

“mmbtu” represents million metric British thermal units.; “bbl” represents barrel.
 

Copyright Business Wire 2010