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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