Atlas Resource Partners, L.P. Reports Operating and Financial Results for the Fourth Quarter and Full Year 2013

  Atlas Resource Partners, L.P. Reports Operating and Financial Results for   the Fourth Quarter and Full Year 2013    *ARP increased its quarterly distribution to $0.58 per limited partner unit     for the fourth quarter 2013, a 4% increase from the third quarter 2013 and     a 21% increase from the prior year quarter   *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 $62.6 million^(1) for the fourth quarter 2013   *Successfully completed fundraising for the 2013 investment program with     $150 million in total funds raised, an increase of approximately 18% over     the 2012 fundraising amount   *Reaffirms guidance in the range of $2.40 to $2.60 per common unit for full     year 2014   *Recent results in the company’s Mississippi Lime position continue to     yield strong levels of oil and liquids production   *ARP also introduced its new monthly distribution policy, declaring an     initial distribution of $0.1933 per common unit for the month of January     2014   *Fourth quarter and full year 2013 financial and operational results to be     discussed on a conference call at 9AM ET on Friday, February 28^th  Business Wire  PHILADELPHIA -- February 27, 2014  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        $ 93,293        $ 31,578        $ 266,783        $ 92,901 production Well construction         75,590          39,219          167,883          131,496 and completion Gathering and        4,037           5,956           15,676           16,267 processing Administration       3,354           3,224           12,277           11,810 and oversight 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          33,567          10,377          97,237           26,624 production Well construction         65,730          34,197          145,985          114,079 and completion Gathering and        4,245           6,306           18,012           19,491 processing Well services        2,506           2,204           9,515            9,280 General and          14,296          20,696          78,063           69,123 administrative Chevron transaction          —               —               —                7,670 expense Depreciation, depletion and        51,702          18,734          136,763          52,582 amortization Asset               38,014        9,507         38,014         9,507    impairment Total costs         210,060       102,021       523,589        308,356  and expenses                                                                      Operating loss       (28,864 )       (17,281 )       (55,934  )       (40,727 )                                                                      Gain (loss) on asset sales          1,048           39              (987     )       (6,980  ) and disposal Interest            (12,179 )      (1,666  )      (34,324  )      (4,195  ) expense                                                                      Net loss             (39,995 )       (18,908 )       (91,245  )       (51,902 )                                                                      Preferred limited             (4,400  )      (1,842  )      (11,992  )      (3,063  ) partner dividends Net loss attributable to owner’s interest,          $ (44,395 )     $ (20,750 )     $ (103,237 )     $ (54,965 ) common limited partners and the general partner                                                                      Allocation of net loss: Portion applicable to owner’s interest (period prior      $ —             $ —             $ —              $ 250 to the transfer of assets on March 5, 2012) Portion applicable to common limited partners and general                                                     partner’s                          (20,750 )                      (55,215 ) interests            (44,395 )                       (103,237 ) (period subsequent to the transfer of assets on March 5, 2012) Net loss attributable to owner’s interest,          $ (44,395 )     $ (20,750 )     $ (103,237 )     $ (54,965 ) common limited partners and the general partner                                                                      Allocation of net loss attributable to common limited partners and the general partner: General partner’s          $ 1,209         $ (266    )     $ 3,344          $ (955    ) interest Common limited partners’           (45,604 )      (20,484 )      (106,581 )      (54,260 ) interest Net loss attributable to common limited            $ (44,395 )     $ (20,750 )     $ (103,237 )     $ (55,215 ) partners and the general partner                                                                      Net loss attributable to common limited partners per unit: Basic and          $ (0.77   )     $ (0.53   )     $ (2.03    )     $ (1.59   ) Diluted                                                                      Weighted average common limited partner units outstanding: Basic and           59,447        39,003        52,528         34,039   Diluted                                                                                  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        863             — Partnerships 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             2,676           11,293 Drilling Partnerships 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             —               2,429 Partnerships 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      $ (0.77   )     $ (0.53   )     $ (2.03   )     $ (1.59  ) partners per unit - basic                                                                      Cash distributions       $ 0.58          $ 0.48          $ 2.19          $ 1.43 paid per unit^(1)                                                                      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          10,087        5,484         36,394        11,399  liquids Total production          $ 93,293       $ 31,578       $ 266,783      $ 92,901  revenues                                                                      Production volume:^(2)(3) Appalachia: ^ (4) Natural gas           45,768          34,134          36,705          33,889 (Mcfd) Oil (Bpd)             452             291             332             278 Natural gas          70            2             22            10      liquids (Bpd) Total (Mcfed)        48,904        35,892        38,825        35,618  Raton/Black Warrior: ^ (4)(5) Natural gas           113,346         —               47,848          — (Mcfd) Oil (Bpd)             —               —               —               — Natural gas          —             —             —             —       liquids (Bpd) Total (Mcfed)        113,346       —             47,848        —       Barnett/Marble Falls: ^ (6) Natural gas           61,625          61,323          65,053          28,855 (Mcfd) Oil (Bpd)             692             784             808             28 Natural gas          2,734         2,501         2,751         473     liquids (Bpd) Total (Mcfed)        82,179        81,032        86,409        31,861  Mississippi Lime/Hunton: ^ (7) Natural gas           5,269           4,895           4,873           1,392 (Mcfd) Oil (Bpd)             252             31              171             8 Natural gas          432           323           322           81      liquids (Bpd) Total (Mcfed)        9,374         7,017         7,834         1,926   Other Operating Areas: ^(4) Natural gas           3,922           5,393           4,408           5,271 (Mcfd) Oil (Bpd)             16              14              18              16 Natural gas          (333    )      415           (378    )      410     liquids (Bpd) Total (Mcfed)        6,018         7,971         6,786         7,827   Total Production: ^(3)(5)(6)(7) Natural gas           229,931         95,845          158,886         69,408 (Mcfd) Oil (Bpd)             1,413           447             1,329           330 Natural gas          3,569         1,935         3,473         974     liquids (Bpd) Total (Mcfed)        259,821       110,137       187,701       77,232                                                                       Average sales prices: ^ (3) Natural gas         $ 3.63          $ 3.04          $ 3.47          $ 3.29 (per Mcf) ^ (8) Oil (per            $ 90.51         $ 90.76         $ 91.01         $ 94.02 Bbl)^(9) Natural gas liquids (per        $ 30.72         $ 30.80         $ 28.71         $ 31.97 Bbl)                                                                      Production costs:^(3)(10) Lease operating expenses per        $ 1.03          $ 0.88          $ 1.09          $ 0.82 Mcfe Production            0.18            0.14            0.18            0.12 taxes per Mcfe Transportation and compression      0.28          0.18          0.24          0.24    expenses per Mcfe Total production          $ 1.49          $ 1.19          $ 1.50          $ 1.19 costs per Mcfe                                                                      Depletion per       $ 2.07          $ 1.71          $ 1.89          $ 1.66 Mcfe^(3)                                                                                       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 (1)   the respective quarter. The cash distribution declared of $0.12 per        limited partner unit for the 1^st 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.                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) (2)    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.                “Mcf” and “Mcfd” represent thousand cubic feet and thousand cubic feet        per day; “Mcfe” and “Mcfed” represent thousand cubic feet equivalents (3)    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.                Appalachia includes ARP’s production located in Pennsylvania, Ohio, New        York and West Virginia; Raton/Black Warrior includes ARP’s production (4)    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.                Volumetric production for Raton/Black Warrior for the year ended (5)    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.                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 (6)    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.                Volumetric production for Mississippi Lime/Hunton for the year ended (7)    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.                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 (8)    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.                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 (9)    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.                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 (10)   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          $ 10,500     $ 3,350      $ 31,500      $ 10,200 expenditures ^(1) Expansion capital             49,041      50,497      232,037      117,026 expenditures Total                        $ 59,541     $ 53,847     $ 263,537     $ 127,226                                                                                 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 ^(1)  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       2013          2012            2013          2012 non-GAAP measures^(1): Net loss             $ (39,995 )     $ (18,908 )     $ (91,245 )     $ (51,902 ) Distributable cash flow not attributable to limited partners                                                            and the general partner prior to       −               −               −               (7,880  ) March 5, 2012 (the date of transfer of assets)^(2) Acquisition and        4,026           8,701           29,923          22,200 related costs Depreciation, depletion and          51,702          18,734          136,763         52,582 amortization Asset impairment       38,014          9,507           38,014          9,507 Amortization of deferred finance       1,007           793             9,649           1,821 costs Non-cash stock compensation           2,471           2,972           12,679          10,833 expense Maintenance capital                (10,500 )       (3,050  )       (28,167 )       (9,300  ) expenditures^(3) Loss (gain) on asset sales and        (1,048  )       (39     )       987             6,980 disposal Chevron transaction            −               −               −               7,670 expense^(4) Adjustment to reflect cash           −               −               −               4,518 impact of derivatives^(5) Premiums paid on swaption derivative contracts              −               −               14,480          5,001 associated with asset acquisitions^(6) Other                 53            −             190           −        Distributable cash flow attributable to      $ 45,730       $ 18,710       $ 123,273      $ 52,030   limited partners and the general partner^(1)(2)                                                                       Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: Gas and oil production           $ 59,726        $ 21,201        $ 169,546       $ 70,795 margin Well construction and       9,860           5,022           21,898          17,417 completion margin Administration and oversight          3,354           3,224           12,277          11,810 margin Well services          2,283           2,493           9,977           10,761 margin Gathering              (208    )       (350    )       (2,336  )       (3,224  ) Cash general and administrative         (7,799  )       (9,023  )       (35,461 )       (36,090 ) expenses^(7) Other, net            186           66            214           115      Adjusted               67,402          22,633          176,115         71,584 EBITDA^(1) Cash interest          (11,172 )       (873    )       (24,675 )       (2,374  ) expense^(8) Maintenance capital               (10,500 )      (3,050  )      (28,167 )      (9,300  ) expenditures^(3) Distributable          45,730          18,710          123,273         59,910 Cash Flow^(1) Distributable cash flow not attributable to limited partners                                                            and the general                                                 partner prior to       −               −               −               (7,880  ) March 5, 2012 (the date of transfer of assets)^(1)(2) Distributable Cash Flow attributable to      $ 45,730       $ 18,710       $ 123,273      $ 52,030   limited partners and the general partner^(1)(2)                                                                       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               −               8,831           25,791          12,041 effective date through closing date^(9) Well construction and completion            (4,760  )      −             −             −        margin earned^(10) Distributable Cash Flow with discretionary adjustments by       $ 40,970       $ 27,541       $ 149,064      $ 64,071   the Board of Directors of the General Partner^(11)                                                                       Distributions        $ 41,781        $ 23,567        $ 143,141       $ 57,441 Paid^(12) per limited          $ 0.58          $ 0.48          $ 2.19          $ 1.43 partner unit                                                                       Excess (shortfall) of distributable cash flow with discretionary                                                   adjustments by the Board of         $ (811    )     $ 3,974         $ 5,923         $ 6,630 Directors of the General Partner after distributions to unitholders^(14)                                                                                          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.            ^(1)   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.         In accordance with prevailing accounting literature, ARP has adjusted ^(2)    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.         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 ^(3)    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.         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 ^(4)    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.         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 ^(5)    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.         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 ^(6)    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.         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 4^th quarter 2012, such amounts         include net cash generated by the DTE assets from October 1, 2012 to ^(9)    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.         This amount reflects well construction and completion margin from the         deployment of capital for the investment partnership programs during         the 3^rd quarter 2013 for which ARP was required to defer recognition ^(10)   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 31^st of         that calendar year to be eligible for an investment in that program.         Including the discretionary adjustments by the Board of Directors of         the General Partner in the determination of quarterly cash ^(11)   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.         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 ^(12)   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.         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 ^(13)   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.          Contact:  Atlas Resource Partners, L.P. Brian J. Begley Vice President - Investor Relations 877-280-2857 215-405-2718 (fax)  
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