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

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

PR Newswire

PITTSBURGH, May 7, 2014

PITTSBURGH, May 7, 2014 /PRNewswire/ --

  oAtlas Resource Partners, L.P. (ARP) to acquire approximately 47 MMboe of
    mature low-decline oil and liquids reserves in northwest Colorado for $420
    million
  oThe acquisition provides stable, high margin cash flow, low-decline
    production, as well as potential valuable development opportunities in the
    position
  oThe transaction will be immediately accretive on a fully financed basis to
    distributable cash flow per unit
  oThe acquisition of GeoMet natural gas properties in West Virginia was
    recently approved by GeoMet shareholders
  oARP's development activities in the liquids rich Mississippi Lime and
    Marble Falls plays continue to yield significant levels of oil and liquids
    production
  oAdjusted earnings before interest, income taxes, depreciation and
    amortization ("Adjusted EBITDA"), a non-GAAP measure, including
    discretionary adjustments by the Board of Directors of the General
    Partner, increased to $64.5 million^(1) for the first quarter 2014
  oFirst quarter 2014 financial and operational results to be discussed on a
    conference call at 9AM ET on Thursday, May 8^th

Atlas Resource Partners, L.P. (NYSE: ARP) ("ARP" or "the Company") has
reported operating and financial results for the first quarter 2014.

Matthew A. Jones, President of ARP, said, "This quarter highlights the
diligence and expertise of our company's operating teams as we were able to
withstand one of the most challenging winter seasons on record and move
forward with our development activities particularly in our liquids rich
development areas. As a result,our company's net oil production has
increasedby approximately 15 percent in the first five weeks of the second
quarter, our current quarter, compared to the first quarter average, and we
anticipate further growth. Entirely through the organic development of our
liquids rich assets, we've grown our net oil production by more than 60
percent since the first quarter of 2013. Lastly, our recently announced
acquisition of oil properties in Colorado is a tremendous addition to our
existing asset portfolio, providing to us stable cash flow and high production
margins, and we look forward to additional opportunities to expand our
business."

  oFirst quarter 2014 Adjusted EBITDA, a non-GAAP measure, including
    discretionary adjustments by the Board of Directors of the General
    Partner, was $64.5 million^(1), compared to $62.6 million for the fourth
    quarter 2013, and $31.4 million for the prior year comparable quarter.
    Results during the quarter were adversely impacted by approximately $3.5
    million due to constrained production volumes caused by severe winter
    weather conditions.
  oDistributable Cash Flow with discretionary adjustments by the Board of
    Directors of the General Partner, a non-GAAP measure, was $42.3
    million^(1), or $0.53 per common unit, for the first quarter 2014,
    compared to $41.0 million for the fourth quarter 2013 and $25.1 million
    for the prior year comparable quarter. Distributable Cash Flow with
    discretionary adjustments by the Board of Directors of the General Partner
    was unfavorably impacted during the quarter by approximately $3.5 million,
    or $0.05 per unit, due to weather-related issues mentioned above. ARP's
    first quarter 2014 cash distribution coverage would have been
    approximately 1.0x inclusive of the weather impact.
  oARP paid monthly cash distributions totaling $0.58 per limited partner
    unit for the first quarter 2014, an approximate 14% increase over the
    prior year first quarter distribution. The most recent ARP distribution
    for the month of March 2014 will be paid on May 15, 2014 to holders of
    record as of May 7, 2014.
  oOn a GAAP basis, net loss was $10.8 million for the first quarter 2014
    compared to a net loss of $5.4 million for the prior year comparable
    period. The loss for each period was caused principally by non-cash
    expenses, specifically depreciation, depletion and amortization in the
    current period from the larger amount of producing oil & gas assets
    compared to the prior year period.



^(1)A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable
Cash Flow is provided in the financial tables of this release. Please see
footnote 7 to the Financial Information table of this release.

Rangely Field Acquisition of Oil Properties in Colorado

On May 7, 2014, ARP announced that it entered into a definitive agreement to
acquire total reserves of approximately 47 million barrels of oil equivalent
("Mmboe") of oil and natural gas liquids ("NGLs"), including proved developed
producing reserves of approximately 25 Mmboe, for $420 million. The acquired
position is located in the Rangely field in northwest Colorado, a mature
tertiary CO2 flood with low-decline oil production. The transaction is subject
to customary purchase price adjustments and is expected to close in the second
quarter 2014, with an effective date of April 1, 2014. The assets generated
net production of approximately 2,900 million barrels of oil equivalents
("Mmboed") in the first quarter 2014.

The acquired assets are expected to provide ARP with a stable, high margin
cash flow stream with a low-decline profile (average 3-4% annual decline rate
over the past 15 years). The asset position is a tertiary oil recovery project
using CO2 flood activity, and the production mix is predominantly oil at 90%,
with the remainder coming from NGLs. ARP will have an approximate 25%
non-operating net working interest in the assets, and Chevron Corporation will
continue as operator. Material capital expenditures and growth projects are
subject to ARP's approval.

Approval of GeoMet Transaction

On February 14, 2014, ARP announced that it entered into a definitive
agreement to acquire approximately 70 Bcfe of natural gas proved reserves in
West Virginia and Virginia from GeoMet, Inc. (OTCQB:GMET) and certain of its
subsidiaries (collectively, "GeoMet") for $107 million, subject to customary
adjustments, with an effective date of January 1, 2014. On May 5, 2014, the
transaction was approved by a majority vote of GeoMet's shareholders, and the
transaction is expected to close in May 2014.

ARP expects to benefit from the mature, low-decline production from the
acquired assets, which will complement the company's existing oil and gas
base. The assets consist of approximately 70 Bcfe of proved reserves in West
Virginia and Virginia, and are 100% natural gas and proved developed.

E&P Operating Highlights

  oAverage net daily production for the first quarter 2014 was 246.6 Mmcfed,
    an increase of approximately 85% from the prior year comparable quarter
    and a decrease of approximately 5% from the fourth quarter 2013. The
    sequential decrease in production was due to the adverse impact from
    winter weather during the first quarter 2014. During much of the period,
    the weather impact affected the ability to service producing wells, namely
    in the Mid-Continent region, and also delayed the connection of newly
    completed wells into sales lines. As a result, oil and gas production from
    certain areas was restricted for periods of time, which directly affected
    realized production margin for the first quarter 2014. ARP has estimated
    the impact was approximately $3.5 million to Adjusted EBITDA from
    weather-related issues in the quarter. The increase in net production from
    the first quarter 2013 was due primarily to the acquisition of producing
    assets from EP Energy in July 2013, located in the Raton Basin (New
    Mexico), Black Warrior Basin (Alabama) and County Line region (Wyoming).
  oARP's realized price for natural gas across all of its regions, excluding
    the effect of financial hedges, was $4.68 per per thousand cubic feet
    ("mcf") in the first quarter 2014, compared to $3.35 per mcf in the
    fourth quarter 2013, a sequential increase of approximately 40%. Net
    realized natural gas prices including the effect of hedge positions was
    $4.07 per mcf for the current period, an increase of $0.44, or 12%, from
    the fourth quarter 2013.

Hedge Positions

  oARP continued to expand its commodity hedge positions on its existing
    production during the first quarter 2014. A summary of ARP's derivative
    positions as of May 7, 2014 is provided in the financial tables of this
    release.

Corporate Expenses & Capital Position

  oCash general and administrative expense was $11.7 million for the first
    quarter 2014, $3.9 million higher than the fourth quarter 2013 and $2.1
    million higher compared with the prior year first quarter. The increase
    compared with the fourth quarter 2013 was due primarily to certain
    administrative and marketing costs associated with ARP's 2013 partnership
    program that were able to capitalized in the prior quarter. ARP
    capitalizes certain amounts of its general and administrative costs
    associated with the partnership programs as a component of its capital
    contributions to the partnership programs. The increase in expense
    compared with the prior year first quarter was principally due to larger
    operations stemming from ARP's expanded asset position.
  oCash interest expense was $11.4 million for the first quarter 2014,
    consistent with the fourth quarter 2013 and $9.1 million higher than the
    prior year first quarter. The increase compared with the prior year
    quarter was primarily due to higher levels of borrowing used to expand
    ARP's operations over the last year.
  oAs of March 31, 2014, ARP had $889 million of total debt, including $366
    million outstanding under its revolving credit facility. ARP had
    approximately $365 million available on its revolving credit facility as
    of the end of the first quarter 2014.

Interested parties are invited to access the live webcast of an investor call
with management regarding Atlas Resource Partners, L.P.'s first quarter 2014
results on Thursday, May 8, 2014 at 9:00 am ET by going to the Investor
Relations section of Atlas Resource's website at
www.atlasresourcepartners.com. For those unavailable to listen to the live
broadcast, the replay of the webcast will be available following the live call
on the Atlas Resource website and telephonically beginning at 1:00 p.m. ET on
May 8, 2014 by dialing 855-859-2056, passcode: 30755727.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production
master limited partnership which owns an interest in over 13,000 producing
natural gas and oil wells, located primarily in Appalachia, the Barnett Shale
(TX), the Mississippi Lime (OK), the Raton Basin (NM) and Black Warrior Basin
(AL). ARP is also the largest sponsor of natural gas and oil investment
partnerships in the U.S. For more information, please visit our website at
www.atlasresourcepartners.com, or contact Investor Relations at
InvestorRelations@atlasenergy.com.

Atlas Energy, L.P. (NYSE: ATLS)is a master limited partnership which owns all
of the general partner Class A units and incentive distribution rights and an
approximate 34% limited partner interest in its upstream oil & gas subsidiary,
Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the
general partner of its midstream oil & gas subsidiary, Atlas Pipeline
Partners, L.P., through all of the general partner interest, all the incentive
distribution rights and an approximate 6% limited partner interest. For more
information, please visit our website at www.atlasenergy.com, or contact
Investor Relations at InvestorRelations@atlasenergy.com.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and
processing segments of the midstream natural gas industry. In Oklahoma,
southern Kansas, Texas, and Tennessee, APL owns and operates 15 active gas
processing plants, 18 gas treating facilities, as well as approximately 11,200
miles of active intrastate gas gathering pipeline. For more information,
visit the Partnership's website at www.atlaspipeline.com or contact
IR@atlaspipeline.com.

Cautionary Note Regarding Forward-Looking Statements

This press release contains forward-looking statements that involve a number
of assumptions, risks and uncertainties that could cause actual results to
differ materially from those contained in the forward-looking statements. ARP
cautions readers that any forward-looking information is not a guarantee of
future performance. Such forward-looking statements include, but are not
limited to, statements about future financial and operating results, resource
and production potential, ARP's plans, objectives, expectations and intentions
and other statements that are not historical facts. Risks, assumptions and
uncertainties that could cause actual results to materially differ from the
forward-looking statements include, but are not limited to, those associated
with general economic and business conditions; ARP's ability to close the
GeoMet acquisition, on the terms described or at all; ARP's ability to obtain
required consents in order to permit the transfer of the assets included in
the GeoMet acquisition; ARP's ability to obtain the required financing for the
GeoMet acquisition, on desirable terms or at all; ARP's ability to realize the
anticipated benefits of the GeoMet transaction; changes in commodity prices
and hedge positions; changes in the estimates of maintenance capital expense;
changes in the costs and results of drilling operations; uncertainties about
estimates of reserves and resource potential; inability to obtain capital
needed for operations; ARP's level of indebtedness; changes in government
environmental policies and other environmental risks; the availability of
drilling equipment and the timing of production; tax consequences of business
transactions; and other risks, assumptions and uncertainties detailed from
time to time in ARP's reports filed with the U.S. Securities and Exchange
Commission, including quarterly reports on Form 10-Q, reports on Form 8-K and
annual reports on Form 10-K. Forward-looking statements speak only as of the
date hereof, and ARP assumes no obligation to update such statements, except
as may be required by applicable law.





ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
                                            Three Months Ended
                                            March 31,
                                            2014               2013
Revenues:
Gas and oil production                      $   96,245      $   46,064
Well construction and completion            49,377             56,478
Gathering and processing                    4,468              3,585
Administration and oversight                1,729              1,085
Well services                               5,479              4,816
Other, net                                  47                 20
 Total revenues                    157,345            112,048
Costs and expenses:
Gas and oil production                      36,792             15,216
Well construction and completion            42,936             49,112
Gathering and processing                    4,413              4,413
Well services                          2,482              2,318
General and administrative                  16,455             17,567
Depreciation, depletion and amortization    50,237             21,208
 Total costs and expenses          153,315            109,834
Operating income                            4,030              2,214
Loss on asset sales and disposal            (1,603)            (702)
Interest expense                            (13,188)           (6,889)
Net loss                                    (10,761)           (5,377)
Preferred limited partner dividends         (4,399)            (1,957)
Net loss attributable to common limited                       
partners and the general partner
                                            $  (15,160)      $   (7,334)
Allocation of net loss attributable to common limited partners and the general
partner:
General partner's interest                  $    2,004      $     301
Common limited partners' interest           (17,164)           (7,635)
Net loss attributable to common limited     $  (15,160)      $   (7,334)
partners and the general partner
Net loss attributable to common limited partners per unit:
Basic and Diluted                           $    (0.28)    $    (0.17)
Weighted average common limited partner units outstanding:
Basic and Diluted                           61,219             43,974





ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
                                      March 31,            December 31,
ASSETS                                2014                 2013
Current assets:
 Cash and cash equivalents       $       1,965  $       1,828
 Accounts receivable             78,127               58,822
 Current portion of derivative   161                  1,891
asset
 Subscriptions receivable        —                    47,692
 Prepaid expenses and other      17,481               10,097
 Total current assets        97,734               120,330
Property, plant and equipment, net    2,125,189            2,120,818
Goodwill and intangible assets, net   32,679               32,747
Long-term derivative asset            23,749               27,084
Other assets, net                     42,554               42,821
                                      $   2,321,905      $   2,343,800
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
 Accounts payable          $      94,472   $      69,346
 Advances from affiliates        24,413               26,742
 Liabilities associated with     —                    49,377
drilling contracts
 Current portion of derivative   22,372               6,353
liability
 Accrued well drilling and       66,199               40,481
completion costs
 Accrued liabilities             38,961               51,416
 Total current liabilities   246,417              243,715
Long-term debt                        889,388              942,334
Asset retirement obligations and      92,110               90,460
other
Commitments and contingencies
Partners' Capital:
 General partner's interest      1,485                4,482
 Preferred limited partners'     180,543              183,477
interests
 Common limited partners'        905,888              852,457
interests
 Class C preferred limited       1,176                1,176
partner warrants
 Accumulated other               4,898                25,699
comprehensive income
Total partners' capital               1,093,990            1,067,291
                                      $   2,321,905     $   2,343,800





ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
                                           Three Months Ended
                                           March 31,
                                           2014              2013
Net loss attributable to common limited    $     (0.28)  $     (0.17)
partners per unit - basic
Cash distributions paid per unit ^(1)      $     0.58   $      0.51
Production revenues (in thousands):
Natural gas                                $   74,190      $    29,056
Oil                                        12,283            8,806
Natural gas liquids                        9,772             8,202
Total production revenues                  $   96,245      $    46,064
Production volume:^(2)(3)
Appalachia: ^ (4)
Natural gas (Mcfd)                         41,146            31,568
Oil (Bpd)                                  415               278
Natural gas liquids (Bpd)                  29                2
Total (Mcfed)                              43,810            33,244
Raton/Black Warrior^: (4)
Natural gas (Mcfd)                         108,368           —
Oil (Bpd)                                  —                 —
Natural gas liquids (Bpd)                  —                 —
Total (Mcfed)                              108,368           —
Barnett/Marble Falls^:
Natural gas (Mcfd)                         57,898            66,069
Oil (Bpd)                                  834               780
Natural gas liquids (Bpd)                  2,570             2,557
Total (Mcfed)                              78,319            86,092
Mississippi Lime/Hunton:
Natural gas (Mcfd)                         5,873             4,757
Oil (Bpd)                                  301               29
Natural gas liquids (Bpd)                  485               243
Total (Mcfed)                              10,587            6,393
Other Operating Areas:^(4)
Natural gas (Mcfd)                         3,402             4,861
Oil (Bpd)                                  19                14
Natural gas liquids (Bpd)                  338               394
Total (Mcfed)                              5,544             7,311
Total Production:^(3)
Natural gas (Mcfd)                         216,688           107,255
Oil (Bpd)                                  1,568             1,101
Natural gas liquids (Bpd)                  3,422             3,197
Total (Mcfed)                              246,628           133,039
Average sales prices: ^ (3)
Natural gas (per Mcf) ^ (5)                $      4.07  $      3.33
Oil (per Bbl)^(6)                          $     87.04   $     88.89
Natural gas liquids (per Bbl) ^ (7)        $     31.73   $     28.51
Production costs:^(3)(8)
 Lease operating expenses per Mcfe  $      1.17  $      0.97
Production taxes per Mcfe                  0.27              0.22
Transportation and compression expenses    0.29              0.16
per Mcfe
Total production costs per Mcfe            $      1.73  $      1.35
Depletion per Mcfe^(3)                     $      2.16  $      1.64

       Represents the cash distributions declared per limited partner unit for
^(1) the respective period and paid by ARP within 45 days after the end of
       each quarter, based upon the distributable cash flow generated during
       the respective quarter.
       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; 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.
       ARP's average sales prices for natural gas before the effects of
       financial hedging were $4.68 per Mcf and $2.90 per Mcf for the three
       months ended March 31, 2014 and 2013, respectively. These amounts
       exclude the impact of subordination of production revenues to investor
^(5)  partners within the investor partnerships. Including the effects of
       subordination, average natural gas sales prices were $3.80 per Mcf
       ($4.42 per Mcf before the effects of financial hedging) and $3.01 per
       Mcf ($2.59 per Mcf before the effects of financial hedging) for the
       three months ended March 31, 2014 and 2013, respectively.
       ARP's average sales prices for oil before the effects of financial
^(6) hedging were $93.18 per barrel and $90.80 per barrel for the three
       months ended March 31, 2014 and 2013, respectively.
       ARP's average sales prices for natural gas liquids before the effects
^(7)  of financial hedging were $35.65 per barrel and $28.74 per barrel for
       the three months ended March 31, 2014 and 2013, 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
^(8) subordination of production revenue to investor partners within ARP's
       investor partnerships. Including the effects of these costs, lease
       operating expenses per Mcfe were $1.10 per Mcfe ($1.66 per Mcfe for
       total production costs) and $0.90 per Mcfe ($1.27 per Mcfe for total
       production costs) for the three months ended March 31, 2014 and 2013,
       respectively.





ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
                                    March 31,          December 31,
                                                       2013
                                    2014
Total debt                          $     889,388  $     942,334
Less: Cash                         (1,965)            (1,828)
Total net debt/(cash)               887,423            940,506
Partners' capital                  1,093,990          1,067,291
Total capitalization                $   1,981,413    $   2,007,797
Ratio of net debt to capitalization 0.45x              0.47x





ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
                                     Three Months Ended
                                     March 31,
                                     2014           2013
Maintenance capital expenditures^(1) $   10,800  $     4,000
Expansion capital expenditures       29,097         54,487
 Total                        $   39,897  $   58,487

     Oil and gas assets naturally decline in future periods and, as such, ARP
     recognizes the estimated capitalized cost of stemming such decline in
     production margin for the purpose of stabilizing its Distributable Cash
     Flow and cash distributions, which it refers to as maintenance capital
     expenditures. ARP calculates the estimate of maintenance capital
     expenditures by first multiplying its forecasted future full year
     production margin by its expected aggregate production decline of proved
     developed producing wells. Maintenance capital expenditures are then the
     estimated capitalized cost of wells that will generate an estimated first
     year margin equivalent to the production margin decline, assuming such
     wells are connected on the first day of the calendar year. ARP does not
     incur specific capital expenditures expressly for the purpose of
     maintaining or increasing production margin, but such amounts are a
     hypothetical subset of wells it expects to drill in future periods,
^(1) including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls
     wells, on undeveloped acreage already leased. Estimated capitalized cost
     of wells included within maintenance capital expenditures are also based
     upon relevant factors, including utilization of public forward commodity
     exchange prices, current estimates for regional pricing differentials,
     estimated labor and material rates and other production costs. Estimates
     for maintenance capital expenditures in the current year are the sum of
     the estimate calculated in the prior year plus estimates for the decline
     in production margin from wells connected during the current year and
     production acquired through acquisitions. ARP considers expansion capital
     expenditures to be any capital expenditure costs expended that are not
     maintenance capital expenditures – generally, this will include
     expenditures to increase, rather than maintain, production margin in
     future periods, as well as land, gathering and processing, and other
     non-drilling capital expenditures.





ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)
                                              Three Months Ended
                                              March 31,
Reconciliation of net loss to non-GAAP        2014             2013
measures^(1):
Net loss                                      $   (10,761)   $   (5,377)
Acquisition and related costs                 2,379            3,714
Depreciation, depletion and amortization      50,237           21,208
Amortization of deferred finance costs        1,812            4,642
Non-cash stock compensation expense           2,345            4,247
Maintenance capital expenditures^(2)          (10,800)         (4,000)
Loss on asset sales and disposal              1,603            702
Other                                         (3)              −
Distributable cash flow attributable to                       
limited partners and the
                                              $   36,812    $   25,136
general partner^(1)
Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
Gas and oil production margin                 $   59,453    $   30,848
Well construction and completion margin       6,441            7,366
Administration and oversight margin           1,729            1,085
Well services margin                          2,997            2,498
Gathering                                     55               (828)
Cash general and administrative expenses^(3)  (11,731)         (9,606)
Other, net                                    44               20
Adjusted EBITDA^(1)                           58,988           31,383
Cash interest expense^(4)                     (11,376)         (2,247)
Maintenance capital expenditures^(2)          (10,500)         (4,000)
Distributable Cash Flow attributable to                       
limited partners and the
                                              $   37,112    $   25,136
 general partner^(1)
Discretionary adjustments considered by the Board of Directors of the General
Partner in the

 determination of quarterly cash distributions:
Net cash from acquisitions from the effective                 
date through closing date^(5)
                                              5,197            −
Distributable Cash Flow with discretionary                    
adjustments by the Board of
                                              $   42,309    $   25,136
 Directors of the General Partner^(6)
Distributions Paid^(7)                        $   45,731    $   25,330
 per limited partner unit                    $     0.58  $     0.51
Excess (shortfall) of distributable cash flow
with discretionary                                            

 adjustments by the Board of Directors of                   
the General Partner after
                                              $    (3,422)  $     (194)
 distributions to unitholders^(8)



    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;
(1) - Ability to incur and service debt and fund capital expansion;
    - The viability of potential acquisitions and other capital expenditure
    projects; and
    - Ability to comply with financial covenants in its Amended Credit
    Facility, which is calculated based upon Adjusted EBITDA.

    DCF is determined by calculating EBITDA, adjusting it for non-cash,
    non-recurring and other items to achieve Adjusted EBITDA, and then
    deducting cash interest expense and maintenance capital expenditures. ARP
    defines EBITDA as net income (loss) plus the following adjustments:
    - Interest expense;
    - Income tax expense;
    - Depreciation, depletion and amortization.

    ARP defines Adjusted EBITDA as EBITDA plus the following adjustments:
    - Asset impairments;
    - Acquisition and related costs;
    - Non-cash stock compensation;
    - (Gains) losses on asset disposal;
    - Cash proceeds received from monetization of derivative transactions;
    - Premiums paid on swaption derivative contracts; and
    - Other items.

    ARP adjusts DCF for non-cash, non-recurring and other items for the sole
    purpose of evaluating its cash distribution for the quarterly period, with
    EBITDA and Adjusted EBITDA adjusted in the same manner for consistency.
    ARP defines DCF as Adjusted EBITDA less the following adjustments:
    - Cash interest expense; and
    - Maintenance capital expenditures.
    Production from oil and gas assets naturally declines in future periods
    and, as such, ARP recognizes the estimated capitalized cost of stemming
    such declines in production margin for the purpose of stabilizing its DCF
    and cash distributions, which it refers to as maintenance capital
    expenditures. ARP calculates the estimate of maintenance capital
    expenditures by first multiplying its forecasted future full year
    production margin by its expected aggregate production decline of proved
    developed producing wells. Maintenance capital expenditures are then the
    estimated capitalized cost of wells that will generate an estimated first
    year margin equivalent to the production margin decline, assuming such
    wells are connected on the first day of the calendar year. ARP does not
    incur specific capital expenditures expressly for the purpose of
    maintaining or increasing production margin, but such amounts are a
    hypothetical subset of wells it expects to drill in future periods,
(2) including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls
    wells, on undeveloped acreage already leased. Estimated capitalized cost
    of wells included within maintenance capital expenditures are also based
    upon relevant factors, including utilization of public forward commodity
    exchange prices, current estimates for regional pricing differentials,
    estimated labor and material rates and other production costs. Estimates
    for maintenance capital expenditures in the current year are the sum of
    the estimate calculated in the prior year plus estimates for the decline
    in production margin from wells connected during the current year and
    production acquired through acquisitions. ARP considers expansion capital
    expenditures to be any capital expenditure costs expended that are not
    maintenance capital expenditures – generally, this will include
    expenditures to increase, rather than maintain, production margin in
    future periods, as well as land, gathering and processing, and other
    non-drilling capital expenditures.
(3) Excludes non-cash stock compensation expense and certain acquisition and
    related costs.
(4) Excludes non-cash amortization of deferred financing costs.
    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.
(5) Under GAAP, such amounts are characterized as purchase price adjustments
    and are reflected in the net purchase price paid for the acquired assets,
    rather than reflected as components of net income or loss for the period.
    For the 1st quarter 2014, such amounts include net cash generated by the
    GeoMet assets from January 1, 2014 to March 31, 2014 of $5.5 million, less
    estimated maintenance capital expenditures of $0.3 million.
    Including the discretionary adjustments by the Board of Directors of the
(6) General Partner in the determination of quarterly cash distributions,
    Adjusted EBITDA would have been $64.5 million for the three months ended
    March 31, 2014.
    Represents the cash distributions declared for the respective period and
(7) paid by ARP within 45 days after the end of each quarter, based upon the
    distributable cash flow generated during the respective quarter.
    ARP seeks to at least maintain its current cash distribution in future
    quarterly periods, and expects to only increase such cash distributions
    when future Distributable Cash Flow amounts allow for it and are expected
    to be sustained. The Partnership's determination of quarterly cash
    distributions and its resulting determination of the amount of excess
    (shortfall) those cash distributions generate in comparison to
    Distributable Cash Flow are based upon its assessment of numerous factors,
(8) including but not limited to future commodity price and interest rate
    movements, variability of well productivity, weather effects, and
    financial leverage. ARP also considers its historical trailing four
    quarters of excess or shortfalls and future forecasted excess or
    shortfalls that its cash distributions generate in comparison to
    Distributable Cash Flow due to the variability of its Distributable Cash
    Flow generated each quarter, which could cause it to have more or less
    excess (shortfalls) generated from quarter to quarter.





ATLAS RESOURCE PARTNERS, L.P.
Hedge Position Summary
(as of May 7, 2014)
Natural Gas
 Fixed Price Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per mmbtu)^(a)  (mmbtus)^(a)
  2014^(b)             $  4.15        45,114,732
 2015                    $  4.24        51,924,492
 2016                    $  4.31        45,746,320
 2017                    $  4.53        24,840,000
 2018                    $  4.72        3,960,000
 Costless Collars
                         Average          Average
 Production Period       Floor Price      Ceiling Price    Volumes
 Ended December 31,      (per mmbtu)^(a)  (per mmbtu)^(a)  (mmbtus)^(a)
  2014^(b)             $  4.22        $  5.12        2,880,000
 2015                    $  4.23        $  5.13        3,480,000
 Put Options – Drilling
 Partnerships
                         Average          Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per mmbtu)^(a)  (mmbtus)^(a)
  2014^(b)             $  3.80        1,350,000
 2015                    $  4.00        1,440,000
 2016                    $  4.15        1,440,000
 WAHA Basis Swaps
                         Average          Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per mmbtu)^(a)  (mmbtus)^(a)
  2014^(b)             $  (0.110)     8,100,000
Natural Gas Liquids
 Crude Oil  Fixed Price Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per bbl)^(a)    (bbls)^(a)
  2014^(b)             $  91.57       79,500
 2015                    $  88.55       96,000
 2016                    $  85.65       84,000
 2017                    $  83.78       60,000
 Mt Belvieu Ethane Purity Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per gallon)     (bbls)^(a)
  2014^(b)             $  0.3025      45,000
 Mt Belvieu Propane Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per gallon)     (bbls)^(a)
  2014^(b)             $  0.9996      220,500
 2015                    $  1.0161      192,000
 Mt Belvieu Butane Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per gallon)     (bbls)^(a)
  2014^(b)             $  1.3075      27,000
 2015                    $  1.2481      36,000
 Mt Belvieu Iso-Butane Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per gallon)     (bbls)^(a)
  2014^(b)             $  1.3225      27,000
 2015                    $  1.2631      36,000
Crude Oil
 Fixed Price Swaps
                         Average
 Production Period       Fixed Price      Volumes
 Ended December 31,      (per bbl)^(a)    (bbls)^(a)
  2014^(b)             $  92.69       409,500
 2015                    $  88.14       567,000
 2016                    $  85.52       225,000
 2017                    $  83.30       132,000
 Costless Collars
                         Average          Average
 Production Period       Floor Price      Ceiling Price    Volumes
 Ended December 31,      (per bbl)^(a)    (per bbl)^(a)    (bbls)^(a)
  2014^(b)             $  84.17       $ 113.31        30,870
 2015                    $  83.85       $ 110.65        29,250

^(a) "mmbtu" represents million metric British thermal units.; "bbl"
     represents barrel.
^(b) Reflects hedges covering the last nine months of 2014.



SOURCE Atlas Resource Partners, L.P.

Website: http://www.atlasresourcepartners.com
Contact: Brian J. Begley, Vice President - Investor Relations, Atlas Resource
Partners, L.P., (877) 280-2857, (215) 405-2718 (fax)
 
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