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

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

  *Atlas Resource Partners’ (ARP) average net production for the third
    quarter 2013 reached a record of 261.4 MMcfed, a 96% increase from the
    prior quarter, due primarily to newly acquired producing reserves in the
    Raton and Black Warrior Basins
  *Adjusted earnings before interest, income taxes, depreciation and
    amortization (“adjusted EBITDA”), including discretionary adjustments by
    the Board of Directors of the General Partner, was $60.7 million^(1) for
    the third quarter 2013
  *Average daily oil production increased by approximately 20% from the prior
    quarter, mainly from ARP’s continued development in the Marble Falls and
    Mississippi Lime
  *ARP’s newly drilled Marcellus Shale wells continue their tremendous
    results, currently sustaining production rates at maximum allowable
    capacity
  *ARP’s Raton and Black Warrior Basin assets continue to generate strong
    benefits for the company from stable, low-cost production
  *Development begins on newly identified productive zones for additional oil
    reserves in the Marble Falls play
  *ARP increased its quarterly distribution to $0.56 per limited partner unit
    for the third quarter 2013, a 4% increase from the second quarter 2013 and
    a 30% increase from the prior year quarter, on approximately 1.1x
    distribution coverage for the period
  *ARP to discuss third quarter 2013 financial and operational results on a
    conference call at 9AM ET on Friday, November 8^th

Business Wire

PHILADELPHIA -- November 7, 2013

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

Matthew A. Jones, President of ARP, said, “Our results this quarter continue
the substantial growth our company has experienced over just a short period of
time. Having expanded our operations through accretive acquisitions and by the
drillbit over the past year and a half, we have significantly grown our proved
reserves (+700%) and distributions to unitholders (+40%) over that time. Our
drilling activities have been strong, exemplified by the tremendous results
from our recently completed Marcellus Shale wells. Now, our enterprise is the
strongest it’s been -- both in asset diversification and our ability to
increase cash flow.”

  *ARP generated adjusted earnings before interest, income taxes,
    depreciation and amortization (“adjusted EBITDA”), including discretionary
    adjustments by the Board of Directors of the General Partner, of $60.7
    million^(1) for the third quarter 2013;
  *On a GAAP basis, net loss was $39.7 million for the third quarter 2013
    compared to a net loss of $10.1 million for the prior year comparable
    period. The loss for each period was caused principally by non-cash
    expenses, including depreciation, depletion and non-cash compensation
    expense.
  *ARP declared a cash distribution of $0.56 per limited partner unit for the
    third quarter 2013, an approximate 4% increase, over the second quarter
    2013 and a 30% increase from the prior year third quarter distribution.
    The third quarter 2013 ARP distribution will be paid on November 14, 2013
    to holders of record as of November 6, 2013. ARP expects to distribute
    between $0.58 and $0.62 per unit for the fourth quarter 2013, and also
    expects full year 2014 distributions to be in a range of $2.40 to $2.60
    per unit.

^(1) Please see footnote 11 to the Financial Information table on page 10 of
this release.

E&P Operating Highlights

  *Average net daily production for the third quarter 2013 was a record 261.4
    million cubic feet of natural gas equivalents per day (“Mmcfed”), an
    increase of approximately 96% from the second quarter 2013. The increase
    in net production from the second quarter 2013 was due primarily to the
    recently acquired 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 third quarter in several of ARP’s key operating areas,
    including the Marcellus Shale, Utica Shale, Marble Falls and Mississippi
    Lime.
  *During the third quarter 2013, ARP connected eight horizontal Marcellus
    Shale wells located in Lycoming County, PA, which demonstrated
    exceptionally strong initial flow rates. Despite limitations of
    infrastructure that have inhibited operation at full capacity, total gross
    daily production from the eight wells reached maximum pipeline capacity of
    approximately 62 million cubic feet per day (“Mmcfd”). The characteristics
    of these well sites are highly favorable compared to other wells in the
    region due to: the thickness and depth of the shale in the area, level of
    porosity (~10-14%), permeability (up to 400 nD), TOC (up to 6%), and a
    high pressure gradient (~0.89 psi/ft).
  *In September 2013, ARP began connecting its five initial wells drilled in
    the Utica-Point Pleasant formation in northern Harrison County, OH. Early
    results indicated higher levels of high-grade condensate than originally
    expected. Midstream service in the Utica Shale has been disrupted due to a
    processing plant fire which occurred in late September 2013. Nonetheless,
    ARP has been able to flow limited amount of production from these wells
    and is in the process of identifying additional third-party capacity in
    order to optimize production.
  *ARP has drilled over 40 wells to date in the oil and liquids rich Marble
    Falls play, primarily in Jack County, TX in which the Company holds
    approximately 75,000 net acres. ARP has now identified additional
    productive zones located above and below the Marble Falls play, including
    the Caddo formation, Bend conglomerates and Chappel Reefs. Early testing
    of these formations has yielded initial production rates of 100-300
    barrels of oil per day. Additional 3-D seismic is being undertaken to
    further develop these formations in conjunction with the Marble Falls.

Hedge Positions

  *ARP continued to expand its commodity hedge positions on its legacy
    production during the third quarter 2013. A summary of ARP’s derivative
    positions as of November 7, 2013 is provided in the financial tables of
    this release.

Corporate Expenses & Capital Position

  *Cash general and administrative expense was $9.6 million for the third
    quarter 2013, $1.1 million higher than the second quarter 2013 and
    slightly higher compared with the prior year third quarter. The increase
    compared with the second quarter 2013 was due primarily to additional
    personnel associated with the EP Energy acquisition, as well as an
    increase in other administrative costs due to timing.
  *Cash interest expense was $7.9 million for the third quarter 2013, an
    increase of $4.5 million compared to the second quarter 2013. The increase
    was primarily due to the recent issuance of $250 million of 9.25% senior
    notes due 2021, which were used to partially finance the acquisition of
    natural gas assets from EP Energy in July 2013.
  *As of September 30, 2013, ARP had $948 million of total debt, including
    $425 million outstanding under its revolving credit facility. ARP had
    approximately $410 million available on its revolving credit facility as
    of the end of the third quarter.

Interested parties are invited to access the live webcast of an investor call
with management regarding Atlas Resource Partners, L.P.’s third  quarter 2013
results on Friday, November 8, 2013 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 11:00 a.m. ET on
November 8, 2013 by dialing 888-286-8010, passcode: 71563674.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production
master limited partnership which owns an interest in over 12,000 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 the Mississippi
Lime play in Oklahoma and southern Kansas, the Woodford Shale in southeastern
Oklahoma, the Permian Basin in western Texas, Eagle Ford Shale in south Texas,
as well as gathering pipelines in the Barnett Shale in east Texas and
Chattanooga Shale in Tennessee, APL owns and operates 14 active gas processing
plants, 18 gas treating facilities, as well as approximately 10,600 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 document contains forward-looking statements that involve a number of
assumptions, risks and uncertainties that could cause actual results to differ
materially from those contained in the forward-looking statements. ARP
cautions readers that any forward-looking information is not a guarantee of
future performance. Such forward-looking statements include, but are not
limited to, statements about future financial and operating results, resource
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 realize the
anticipated benefits of its acquisitions; 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              Nine Months Ended
                   September 30,                   September 30,
                   2013          2012            2013          2012
Revenues:
Gas and oil        $ 80,332        $ 24,699        $ 173,490       $ 61,323
production
Well
construction         10,964          36,317          92,293          92,277
and completion
Gathering and        3,591           4,134           11,639          10,311
processing
Administration       4,447           4,440           8,923           8,586
and oversight
Well services        5,023           5,086           14,703          15,344
Other, net          (13,272 )      67            (14,589 )      (4,952  )
Total revenues      91,085        74,743        286,459       182,889 
                                                                   
Costs and
expenses:
Gas and oil          29,419          7,295           63,670          16,247
production
Well
construction         9,534           31,581          80,255          79,882
and completion
Gathering and        4,395           4,558           13,767          13,185
processing
Well services        2,386           2,232           7,009           7,076
General and          31,983          16,147          63,767          48,427
administrative
Chevron
transaction          —               7,670           —               7,670
expense
Depreciation,
depletion and       41,656        13,918        85,061        33,848  
amortization
Total costs         119,373       83,401        313,529       206,335 
and expenses
                                                                   
Operating loss       (28,288 )       (8,658  )       (27,070 )       (23,446 )
                                                                   
Gain (loss) on
asset sales          (661    )       2               (2,035  )       (7,019  )
and disposal
Interest            (10,748 )      (1,423  )      (22,145 )      (2,529  )
expense
                                                                   
Net loss             (39,697 )       (10,079 )       (51,250 )       (32,994 )
                                                                   
Preferred
limited             (3,564  )      (1,221  )      (7,592  )      (1,221  )
partner
dividends
Net loss
attributable
to owner’s
interest,          $ (43,261 )     $ (11,300 )     $ (58,842 )     $ (34,215 )
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                          (11,300 )                     (34,465 )
interests            (43,261 )                       (58,842 )
(period
subsequent to
the transfer
of assets on
March 5, 2012)
Net loss
attributable
to owner’s
interest,          $ (43,261 )     $ (11,300 )     $ (58,842 )     $ (34,215 )
common limited
partners and
the general
partner
                                                                   
Allocation of net loss attributable to common limited partners and the general
partner:
General
partner’s          $ 812           $ (226    )     $ 2,135         $ (689    )
interest
Common limited
partners’           (44,073 )      (11,074 )      (60,977 )      (33,776 )
interest
Net loss
attributable
to common
limited            $ (43,261 )     $ (11,300 )     $ (58,242 )     $ (34,465 )
partners and
the general
partner
                                                                   
Net loss attributable to common limited partners per unit:
Basic and          $ (0.74   )     $ (0.32   )     $ (1.21   )     $ (1.06   )
Diluted
                                                                   
Weighted average common limited partner units outstanding:
Basic and           59,440        35,068        50,197        31,865  
Diluted
                                                                   


ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
                                                             
                                                September 30,     December 31,
ASSETS                                          2013              2012
Current assets:
Cash and cash equivalents                       $  1,452          $  23,188
Accounts receivable                                59,669            38,718
Current portion of derivative asset                19,474            12,274
Subscriptions receivable                           13,900            55,357
Prepaid expenses and other                        11,610           9,063
Total current assets                               106,105           138,600
                                                                  
Property, plant and equipment, net                 2,175,754         1,302,228
Goodwill and intangible assets, net                32,843            33,104
Long-term derivative asset                         28,500            8,898
Long-term derivative receivable from               182               —
Drilling Partnerships
Other assets, net                                 43,468           16,122
                                                $  2,386,852      $  1,498,952
                                                                  
LIABILITIES AND PARTNERS’ CAPITAL
                                                                  
Current liabilities:
Accounts payable                                $  74,686         $  59,549
Advances from affiliates                           23,559            5,853
Liabilities associated with drilling               —                 67,293
contracts
Current portion of derivative liability            318               —
Current portion of derivative payable to           4,932             11,293
Drilling Partnerships
Accrued well drilling and completion costs         47,149            47,637
Accrued liabilities                               33,873           25,388
Total current liabilities                          184,517           217,013
                                                                  
Long-term debt                                     948,279           351,425
Long-term derivative liability                     —                 888
Long-term derivative payable to Drilling           —                 2,429
Partnerships
Asset retirement obligations and other             84,127            65,191
                                                                  
Commitments and contingencies
                                                                  
Partners’ Capital:
General partner’s interest                         5,716             7,029
Preferred limited partners’ interests              183,325           96,155
Common limited partners’ interests                 929,474           737,253
Class C preferred limited partner warrants         1,176             —
Accumulated other comprehensive income            50,238           21,569
Total partners’ capital                           1,169,929        862,006
                                                $  2,386,852      $  1,498,952
                                                                  


ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
                                               
                     Three Months Ended             Nine Months Ended
                     September 30,                  September 30,
                     2013          2012           2013          2012
                                                                    
Net loss
attributable to
common limited       $ (0.74   )     $ (0.32  )     $ (1.21   )     $ (1.06  )
partners per
unit - basic
                                                                    
Cash
distributions        $ 0.56          $ 0.43         $ 1.61          $ 0.95
paid per
unit^(1)
                                                                    
Production
revenues (in
thousands):
Natural gas          $ 57,350        $ 19,945       $ 114,789       $ 47,789
Oil                    12,993          2,239          32,394          7,619
Natural gas           9,989         2,515        26,307        5,915  
liquids
Total production     $ 80,332       $ 24,699      $ 173,490      $ 61,323 
revenues
                                                                    
Production
volume:^(2)(3)
Appalachia: ^
(4)
Natural gas            38,594          38,123         33,651          33,807
(Mcfd)
Oil (Bpd)              312             259            291             273
Natural gas           12            2            5             14     
liquids (Bpd)
Total (Mcfed)         40,541        39,687       35,428        35,530 
Raton/Black
Warrior: ^
(4)(5)
Natural gas            115,354         —              25,775          —
(Mcfd)
Oil (Bpd)              —               —              —               —
Natural gas           —             —            —             —      
liquids (Bpd)
Total (Mcfed)         115,354       —            25,775        —      
Barnett/Marble
Falls: ^ (6)
Natural gas            66,145          49,440         66,208          21,278
(Mcfd)
Oil (Bpd)              899             2              847             1
Natural gas           2,961         865          2,757         230    
liquids (Bpd)
Total (Mcfed)         89,306        54,642       87,834        22,663 
Mississippi
Lime/Hunton:
^(7)
Natural gas            5,475           5,100          4,739           216
(Mcfd)
Oil (Bpd)              285             42             144             —
Natural gas           366           340          285           —      
liquids (Bpd)
Total (Mcfed)         9,382         7,391        7,315         216    
Other Operating
Areas: ^(4)
Natural gas            4,321           5,363          4,571           5,230
(Mcfd)
Oil (Bpd)              21              16             19              17
Natural gas           395           412          394           408    
liquids (Bpd)
Total (Mcfed)         6,815         7,932        7,044         7,780  
Total Production
Per Day:
^(4)(5)(6)
Natural gas            191,020         88,208         134,945         60,531
(Mcfd)
Oil (Bpd)              1,517           277            1,301           291
Natural gas           3,734         1,067        3,441         652    
liquids (Bpd)
Total (Mcfed)         222,529       96,275       163,397       66,189 
                                                                    
Average sales
prices: ^ (3)
Natural gas (per     $ 3.46          $ 3.01         $ 3.39          $ 3.42
Mcf) ^ (8)
Oil (per             $ 93.07         $ 87.86        $ 91.19         $ 95.70
Bbl)^(9)
Natural gas
liquids (per         $ 29.08         $ 25.61        $ 28.01         $ 33.09
Bbl)
                                                                    
Production
costs:^(3)(10)
Lease operating
expenses per         $ 1.15          $ 0.75         $ 1.12          $ 0.80
Mcfe
Production taxes       0.11            0.13           0.17            0.12
per Mcfe
Transportation
and compression       0.24          0.25         0.22          0.27   
expenses per
Mcfe
Total production     $ 1.50          $ 1.13         $ 1.51          $ 1.19
costs per Mcfe
                                                                    
Depletion per        $ 1.95          $ 1.42         $ 1.80          $ 1.64
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
^(1)    during 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
^(2)    (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.
        
        “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; Coalbed Methane 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 per day for Raton/Black Warrior for the three
        months ended September 30, 2013 includes production per day for the
        61-day period from August 1, 2013, the date we began recognizing
        production from the assets following the completion of the
^(5)    acquisition, through September 30, 2013. Total Raton/Black Warrior
        production per day for the nine months ended September 30, 2013
        represents volume production for the full 273-day period. Total
        production per day represents total production volume over the 92 and
        273 days within the three and nine months ended September 30, 2013,
        respectively.
        
        Volumetric production per day for Barnett for the three months ended
        September 30, 2012 includes production per day associated with the
        Titan operational assets for the 68-day period from July 25, 2012, the
        date of acquisition, through September 30, 2012. Total Barnett
^(6)    production per day for the nine months ended September 30, 2012
        represents Barnett volume production for the full 274-day period.
        Total production per day represents total production volume over the
        92 and 274 days within the three and nine months ended September 30,
        2012, respectively.
        
        Volumetric production per day for Mississippi Lime for the three
        months ended September 30, 2012 includes production per day associated
        with the acquisition of the remaining 50% interest in Equal’s
        operational assets for the 7-day period from September 24, 2012, the
^(7)    date of acquisition, through September 30, 2012. Total Mississippi
        Lime production per day for the nine months ended September 30, 2012
        represents volume production for the full 274-day period. Total
        production per day represents total production volume over the 92 and
        274 days within the three and nine months ended September 30, 2012,
        respectively.
        
        ARP’s average sales prices for natural gas before the effects of
        financial hedging were $3.20 per Mcf and $2.46 per Mcf for the three
        months ended September 30, 2013 and 2012, respectively, and $3.19 per
        Mcf and $2.60 per Mcf for the nine months ended September 30, 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 $3.26 per Mcf ($3.01 per Mcf before the effects
        of financial hedging) and $2.46 per Mcf ($1.91 per Mcf before the
        effects of financial hedging) for the three months ended September 30,
        2013 and 2012, respectively, and $3.12 per Mcf ($2.92 per Mcf before
        the effects of financial hedging) and $2.88 per Mcf ($2.07 per Mcf
        before the effects of financial hedging) for the nine months ended
        September 30, 2013 and 2012, respectively.
        
        ARP’s average sales prices for oil before the effects of financial
        hedging were $104.03 per barrel and $84.30 per barrel for the three
^(9)    months ended September 30, 2013 and 2012, respectively, and $96.50 per
        barrel and $93.38 per barrel for the nine months ended September 30,
        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 $1.09 per Mcfe ($1.44 per Mcfe for
        total production costs) and $0.44 per Mcfe ($0.82 per Mcfe for total
        production costs) for the three months ended September 30, 2013 and
        2012, respectively, and $1.04 per Mcfe ($1.43 per Mcfe for total
        production costs) and $0.50 per Mcfe ($0.90 per Mcfe for total
        production costs) for the nine months ended September 30, 2013 and
        2012, respectively.
        


ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
                                                     
                                        September 30,     December 31,
                                        2013              2012
Total debt                              $ 948,279         $ 351,425
Less: Cash                               (1,452    )      (23,188   )
Total net debt/(cash)                     946,827           328,237
                                                          
Partners’ capital                        1,169,929       862,006   
                                                          
Total capitalization                    $ 2,116,756      $ 1,190,243 
                                                          
Ratio of net debt to capitalization     0.45x             0.28x
                                                          


ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
                                                   
                              Three Months Ended        Nine Months Ended
                              September 30,             September 30,
                              2013       2012         2013        2012
Maintenance capital           $ 10,000     $ 3,350      $ 21,000      $ 6,850
expenditures ^(1)
Expansion capital              63,944      24,377      182,996      66,529
expenditures
Total                         $ 73,944     $ 27,727     $ 203,996     $ 73,379
                                                                      

     
       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 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
^(1)   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              Nine Months Ended
                     September 30,                   September 30,
Reconciliation
of net loss to       2013          2012            2013          2012
non-GAAP
measures^(1):
Net loss             $ (39,697 )     $ (10,079 )     $ (51,250 )     $ (32,994 )
Distributable
cash flow not
attributable to
limited partners
and the general        −               −               −               (7,880  )
partner prior to
March 5, 2012
(the date of
transfer of
assets)^(2)
Acquisition and        19,417          2,274           25,897          13,499
related costs
Depreciation,
depletion and          41,656          13,918          85,061          33,848
amortization
Amortization of
deferred finance       2,847           498             8,642           1,028
costs
Non-cash stock
compensation           2,959           4,846           10,208          7,861
expense
Maintenance
capital                (9,167  )       (3,050  )       (17,667 )       (6,250  )
expenditures^(3)
Loss (gain) on
asset sales and        661             (2      )       2,035           7,019
disposal
Chevron
transaction            −               7,670           −               7,670
expense^(4)
Adjustment to
reflect cash           −               656             −               4,518
impact of
derivatives^(5)
Premiums paid on
swaption
derivative
contracts             13,308        25            14,617        5,001   
associated with
asset
acquisitions^(6)
Distributable
cash flow
attributable to      $ 31,984       $ 16,756       $ 77,543       $ 33,320  
limited partners
and the general
partner^(1)(2)
                                                                     
Supplemental Adjusted EBITDA and Distributable
Cash Flow Summary:
Gas and oil
production           $ 50,913        $ 18,060        $ 109,820       $ 49,594
margin
Well
construction and       1,430           4,736           12,038          12,395
completion
margin
Administration
and oversight          4,447           4,440           8,923           8,586
margin
Well services          2,637           2,854           7,694           8,268
margin
Gathering              (804    )       (424    )       (2,128  )       (2,874  )
Cash general and
administrative         (9,607  )       (9,027  )       (27,662 )       (27,067 )
expenses^(7)
Other, net            36            92            28            49      
Adjusted               49,052          20,731          108,713         48,951
EBITDA^(1)
Cash interest          (7,901  )       (925    )       (13,503 )       (1,501  )
expense^(8)
Maintenance
capital               (9,167  )      (3,050  )      (17,667 )      (6,250  )
expenditures^(3)
Distributable          31,984          16,756          77,543          41,200
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      $ 31,984       $ 16,756       $ 77,543       $ 33,320  
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               5,244           1,710           25,791          3,210
effective date
through closing
date^(9)
Well
construction and
completion            4,760         −             4,760         −       
margin
earned^(10)
Distributable
Cash Flow with
discretionary
adjustments by       $ 41,988       $ 18,466       $ 108,094      $ 36,530  
the Board of
Directors of the
General
Partner^(11)
                                                                     
Distributions        $ 39,981        $ 17,512        $ 101,360       $ 33,874
Paid^(12)
per limited          $ 0.56          $ 0.43          $ 1.61          $ 0.95
partner unit
                                                                     
Excess
(shortfall) of
distributable
cash flow with
discretionary                                                   
adjustments by
the Board of         $ 2,007         $ 954           $ 6,734         $ 2,656
Directors of the
General Partner
after
distributions to
unitholders^(13)
                                                                               

      
        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 it’s 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

^(1)    - 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.
        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.
        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 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
^(3)    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 nine
        months ended September 30, 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
^(5)    nine months ended September 30, 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 3^rd quarter 2013, such amounts
        include net cash generated by the EP Energy assets of $6.9 million for
        period from July 1, 2013 to July 31, 2013, less pro forma interest
        expense of $0.8 million and estimated maintenance capital expenditures
^(9)    of $0.8 million. For the 3^rd quarter 2012, such amounts include net
        cash generated by the Titan assets from July 1, 2012 to July 24, 2012
        and the Equal assets from July 1, 2012 to September 23, 2012 of $2.0
        million, less estimated maintenance capital expenditures of $0.3
        million. For the nine months ended September 30, 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 nine months ended September 30, 2012, such
        amounts include net cash generated by the 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 $3.8 million, less estimated maintenance capital expenditures of
        $0.6 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 $60.7 million and $22.7
        million for the three months ended September 30, 2013 and 2012,
        respectively, and $145.9 million and $52.8 million for the nine months
        ended September 30, 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 November 7, 2013)
                                                       
Natural Gas
                                                              
Fixed Price Swaps
                       Average
Production Period      Fixed Price         Volumes
Ended December 31,     (per mmbtu)^(a)     (mmbtus)^(a)
2013^(b)               $ 3.91              15,597,417
2014                   $ 4.15              60,152,976
2015                   $ 4.24              50,274,492
2016                   $ 4.32              43,946,320
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)
2013^(b)               $ 4.40              $ 5.44             1,380,000
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)
2013^(b)               $ 93.66             27,000
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)
                                                              
2013^(b)               $ 1.0835            69,000
2014                   $ 0.9996            294,000
2015                   $ 1.0125            132,000
                                                              
Mt Belvieu Butane Swaps
                       Average
Production Period      Fixed Price         Volumes
Ended December 31,     (per gallon)        (bbls)^(a)
                                                              
2014                   $ 1.2750            18,000
2015                   $ 1.2150            18,000
                                                              
Mt Belvieu Iso-Butane Swaps
                       Average
Production Period      Fixed Price         Volumes
Ended December 31,     (per gallon)        (bbls)^(a)
                                                              
2014                   $ 1.2900            18,000
2015                   $ 1.2275            18,000
                                                              
Crude Oil
                                                              
Fixed Price Swaps
                       Average
Production Period      Fixed Price         Volumes
Ended December 31,     (per bbl)^(a)       (bbls)^(a)
2013^(b)               $ 93.74             127,650
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)
2013^(b)               $ 90.00             $ 116.40           15,000
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.
^(b)   Reflects hedges covering the last three months of 2013.
       

Contact:

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