Atlas Pipeline Partners, L.P. Reports Second Quarter 2013 Results

      Atlas Pipeline Partners, L.P. Reports Second Quarter 2013 Results

- Record processed gas volumes exceed 1.25 billion cubic feet per day (BCFD)
in second quarter 2013

- Adjusted EBITDA for second quarter 2013 was $86.3 million, a 75.9% increase
year-over-year

- Distributable Cash Flow for second quarter 2013 of $58.0 million, a 77.0%
increase year-over-year

- Partnership reaffirms 2013-2014 previously stated guidance

- Previously announced distribution of $0.62 per common limited partner unit,
a 10.7% increase year-over-year

- WestOK 200 MMCFD expansion full after only 9 months in operation; Another
200 MMCFD expansion announced last month at WestTX

PR Newswire

PHILADELPHIA, Aug. 5, 2013

PHILADELPHIA, Aug. 5, 2013 /PRNewswire/ --Atlas Pipeline Partners, L.P.
(NYSE: APL) ("APL", "Atlas Pipeline", or the "Partnership") today reported
adjusted earnings before interest, income taxes, depreciation and amortization
("Adjusted EBITDA"), of $86.3 million for the second quarter of 2013, driven
primarily by a continued increase in volumes across the Partnership's
gathering and processing systems. Processed natural gas volumes averaged
1,253 million cubic feet per day ("MMCFD"), an 84.0% increase over the second
quarter of 2012. Distributable Cash Flow was $58.0 million for the second
quarter of 2013, or $0.78 per average common limited partner unit, compared to
$32.8 million for the prior year's second quarter. The Partnership recognized
net income of $10.1 million for the second quarter of 2013, compared with net
income of $74.9 million for the prior year's second quarter.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures,
which are reconciled to their most directly comparable GAAP measures in the
tables included at the end of this news release. The Partnership believes
these measures provide a more accurate comparison of the operating results for
the periods presented.

On July 23, 2013, the Partnership declared a distribution for the second
quarter of 2013 of $0.62 per common limited partner unit to holders of record
on August 7, 2013, which will be paid on August 14, 2013. This distribution
represents Distributable Cash Flow coverage per limited partner unit of
approximately 1.07x on a fully diluted basis for the second quarter of 2013.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, "We
reported solid results for the second quarter and were pleased to have raised
our quarterly distribution more than 10% versus this period last year.
Contributing to the increase was the much needed increased liquids takeaway
capacity at our WestOK and WestTX systems and the start-up of the Driver plant
in West Texas. We are very focused on aggressively pursuing opportunities in
the second half of the year in all of our operating areas and, specifically,
are excited to continue to integrate the new Arkoma and SouthTX assets that we
have recently acquired to achieve their full operating potential." 

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its
revolving credit facility) of $540.7 million as of June 30, 2013. Total debt
outstanding was $1,635.8 million at June 30, 2013, compared to $1,179.9
million at December 31, 2012, an increase of $455.9 million. Based upon total
debt outstanding at June 30, 2013, total leverage was approximately 4.8x for
purposes of calculations under our revolving credit facility, and debt to
total capital was 41%.

* * *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding
further protection for 2013 through 2016. As of July 31, 2013, the
Partnership has natural gas, natural gas liquids and condensate protection in
place for the full years of 2013, 2014, and 2015 for approximately 71%, 72%,
and 38% respectively, of associated margin value (exclusive of ethane). The
Partnership has also begun to add to protection in 2016. Counterparties to
the Partnership's risk management activities consist of investment grade
commercial banks that are lenders under the Partnership's credit facility, or
affiliates of those banks. A table summarizing the Partnership's risk
management portfolio as of July 31, 2013 is included in this release.

* * *

Operating Results

The Partnership continues to report record volumes, and with the addition of
the SouthTX assets, is now processing, on average, over 1.25 billion cubic
feet per day of natural gas per day. Gross margin from operations was $108.7
million for the second quarter 2013, compared to $60.8 million for the prior
year period, led by increasing producer activity in APL's area of operations.
Gross margin, a non-GAAP financial measure, includes natural gas and liquids
sales and transportation, processing and other fees, less purchased product
costs and non-cash gains (or losses) included in these items. The higher
gross margin for the quarter was primarily due to the increased volumes and
expansions that have been completed on the WestOK, WestTX, and Velma systems,
as well as the newly acquired Arkoma system and SouthTX system, and was
partially offset by lower natural gas liquids ("NGL") prices. The gross
margin for the quarter does not include approximately $2.8 million of realized
derivative settlement gains, which are excluded in the calculation of gross
margin, compared to $2.0 million realized derivative settlement gains excluded
from gross margin in the second quarter of 2012.

WestTX System

The WestTX system's average natural gas processed volume was 313.5 MMCFD for
the second quarter 2013, compared to 236.2 MMCFD for the second quarter of
2012. Increased volumes are primarily due to the April 12, 2013 completion of
the Driver plant, which increased processing capacity on the WestTX system by
200 MMCFD. Average NGL production volumes were 39,901 barrels per day ("BPD")
for the second quarter 2013, a 21.8% increase from second quarter 2012. This
system continues to operate in ethane rejection due to the value of ethane
compared to residue natural gas. The Partnership expects processed volumes on
this system to continue to increase as producers continue to pursue their
drilling plans over the coming years. 

WestOK System

The WestOK system had average natural gas processed volume of 483.5 MMCFD for
the second quarter, a 53.1% increase from second quarter 2012. Average NGL
production was 22,233 BPD for the second quarter 2013, a 54.6% increase from
second quarter 2012, due to increased production on the gathering systems and
the start-up of the Waynoka II plant in September 2012. The WestOK system is
also operating in ethane rejection for economic reasons. The Partnership
announced during the quarter that incremental NGL take-away from the Waynoka
facilities became available on April 2, 2013 with the connection to DCP
Midstream Partners, L.P.'s Southern Hills pipeline. 

Velma System

The Velma system's average natural gas processed volume was 132.7 MMCFD for
the second quarter 2013, a 2.8% increase from second quarter 2012. The
increase is primarily due to additional production gathered from continued
producer activity in the liquids-rich portion of the Woodford Shale and
Ardmore Basin. Average NGL production increased to 16,201 BPD for the second
quarter 2013, up approximately 13.9% compared to second quarter 2012, due to
the increase in overall processed volumes.

Arkoma System

The Partnership acquired the Arkoma system in December 2012 through the
acquisition of Cardinal Midstream L.L.C. The assets acquired include gas
gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma
and Texas, including a 60% interest in a joint venture with MarkWest Energy
Partners, L.P., known as Centrahoma Processing, LLC ("Centrahoma"). The Arkoma
gathering and processing system is located in the Arkoma Basin in southeastern
Oklahoma and had average natural gas processed volumes of 202.1 MMCFD and
produced 25,590 BPD of NGLs during the second quarter of 2013. The Arkoma
system has total gross name-plate processing capacity of 220 MMCFD, including
the 120 MMCFD Tupelo plant, of which the Partnership owns 100%. The remaining
processing capacity is owned by Centrahoma.

SouthTX System

The Partnership acquired the SouthTX system in April 2013 through the
acquisition of TEAK Midstream L.L.C. The assets acquired include gas
gathering and processing facilities and a co-generation facility located in
south Texas within the Eagle Ford shale region. The SouthTX system has a
total gross name-plate processing capacity of 200 MMCFD with the Silver Oak I
plant, and will have a capacity of 400 MMCFD once the Silver Oak II plant goes
into service, which is expected to be during first quarter 2014. The system
had average natural gas processed volumes of 121.3 MMCFD and produced 15,041
BPD of NGLs during the second quarter of 2013.

Corporate and Other

Net of deferred financing costs, interest expense increased to $20.8 million
for the second quarter of 2013, up 156.1% as compared with the second quarter
of 2012. This increase was due to financing the Partnership's acquisitions
and capital expenditure program during 2012 and 2013, including the issuance
of 6.625% senior unsecured notes due 2020 in September and December 2012, the
February 2013 issuance of 5.875% senior unsecured notes due 2023, and the May
2013 issuance of 4.750% senior unsecured notes due 2021. The 5.875% senior
unsecured notes due 2023 were issued in connection with the redemption of the
Partnership's 8.75% Senior Notes due 2018.

* * *

Interested parties are invited to access the live webcast of an investor call
with management regarding the Partnership's second quarter 2013 results on
Tuesday, August 6, 2013 at 10:00 am ET by going to the Investor Relations
section of the Partnership's website at www.atlaspipeline.com. An audio
replay of the conference call will also be available beginning at 12:00 pm ET
on Tuesday, August 6, 2013. To access the replay, dial 1-888-286-8010 and
enter conference code 78328957.

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 10,600
miles of active intrastate gas gathering pipeline. APL also has a 20%
interest in West Texas LPG Pipeline Limited Partnership, which is operated by
Chevron Corporation. For more information, visit the Partnership's website at
www.atlaspipeline.com or contact IR@atlaspipeline.com.

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.

Certain matters discussed within this press release are forward-looking
statements. Although Atlas Pipeline Partners, L.P. believes the expectations
reflected in such forward-looking statements are based on reasonable
assumptions, it can give no assurance that its expectations will be attained.
Atlas Pipeline does not undertake any duty to update any statements contained
herein (including any forward-looking statements), except as required by law.
Factors that could cause actual results to differ materially from expectations
include general industry considerations, regulatory changes, changes in
commodity process and local or national economic conditions and other risks
detailed from time to time in Atlas Pipeline's reports filed with the SEC,
including quarterly reports on Form 10-Q, current reports on Form 8-K and
annual reports on Form 10-K.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary^(1)

(unaudited; in thousands except per unit amounts)
                            Three Months Ended           Six Months Ended
                            June 30,                     June 30,
                            2013           2012          2013        2012
Revenue:
Natural gas and liquids     $   491,230    $  238,801    $ 875,078   $ 528,026
sales
Transportation, processing      40,306        14,878       73,031      27,559
and other fees^(2)
Derivative gain, net            27,107        67,847       15,024      55,812
Other income, net               2,296         2,588        5,718       5,003
Total revenues                  560,939       324,114      968,851     616,400
Costs and expenses:
Natural gas and liquids         424,216       195,103      749,756     428,208
cost of sales
Plant operating                 24,147        14,600       45,418      28,481
Transportation and              623           212          1,211       476
compression
General and administrative      9,110         7,505        18,524      16,472
General and administrative
– non-cash unit-based           3,436         2,940        7,820       3,918
compensation^(3)
Other                           18,370        (161)        18,900      (195)
Depreciation and                46,383        21,712       76,841      42,554
amortization
Interest                        22,581        9,269        41,267      17,977
Total costs and expenses        548,866       251,180      959,737     537,891
Equity income in joint          (472)         1,917        1,568       2,813
ventures
Gain (loss) on asset sales      (1,519)       -            (1,519)     -
and other
Loss on early                   (19)          -            (26,601)    -
extinguishment of debt
Income from continuing          10,063        74,851       (17,438)    81,322
operations
Income tax benefit              28                         37
Net income                      10,091        74,851       (17,401)    81,322
Income attributable to          (1,810)       (1,061)      (3,179)     (2,597)
non-controlling interests
Income unit imputed             (6,729)       -            (6,729)     -
dividend effect
Preferred unit dividends        (5,341)       -            (5,341)     -
Net income attributable to
common limited partners and $   (3,789)    $  73,790     $ (32,650)  $ 78,725
the General Partner
Net income attributable to
common limited partners per
unit:
Basic and diluted:          $   (0.11)     $  1.30       $ (0.57)    $ 1.37
Weighted average common
limited partner units           74,340        53,646       69,520      53,633
(basic)
Weighted average common
limited partner units           74,340        54,510       69,520      54,262
(diluted)
(1) Based on the GAAP statements of operations to be included in Form
10-Q, with additional detail of certain items included
(2) Includes affiliate revenues related to transportation and processing
provided to Atlas Resource Partners, L.P
(3) Non-cash costs associated with unit-based compensation, which have
been reflected in the general and administrative costs and expenses, the
category associated with the direct personnel cash costs in the GAAP
statements of operations to be included in Form 10-Q. General and
administrative also includes any compensation reimbursement to affiliates



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)
                         Three Months Ended         Six Months Ended
                         June 30,                   June 30,
                         2013           2012        2013           2012
Summary Cash Flow Data:
Cash provided by         $ 30,465       $ 21,784    $ 65,721       $ 64,531
operating activities
Cash provided by (used     (1,107,853)    (84,551)    (1,216,244)    (182,827)
in) investing activities
Cash provided by (used     1,090,208      62,856      1,168,206      118,385
in) financing activities
Capital Expenditure
Data:
Maintenance capital      $ 3,848        $ 4,000     $ 7,703        $ 8,510
expenditures
Expansion capital          103,345        61,221      208,006        137,878
expenditures
Acquisitions               1,000,785      19,454      1,000,785      36,689
Total                    $ 1,107,978    $ 84,675    $ 1,216,494    $ 183,077





ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)


                                      June 30,     December 31,
ASSETS
                                      2013         2012
Current assets:
Cash and cash equivalents             $ 21,081     $  3,398
Other current assets                    294,940       216,677
Total current assets                    316,021       220,075
Property, plant and equipment, net      2,623,078     2,200,381
Intangible assets, net                  1,072,164     518,645
Investment in joint ventures            232,090       86,002
Other assets, net                       60,821        40,535
                                      $ 4,304,174  $  3,065,638
LIABILITIES AND EQUITY
Current liabilities                   $ 304,816    $  253,519
Long-term debt, less current portion    1,635,297     1,169,083
Deferred income taxes, net              35,513        30,258
Other long-term liability               6,387         6,370
Total partners' capital                 2,277,682     1,539,177
Non-controlling interest                44,479        67,231
Total equity                            2,322,161     1,606,408
                                      $ 4,304,174  $  3,065,638





ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)


                        Three Months Ended            Six Months Ended
                        June 30,                      June 30,
                        2013           2012           2013          2012
Reconciliation of net
income to other

non-GAAP measures^(1):
Net income              $  10,091      $  74,851      $  (17,401)   $ 81,322
Depreciation and           46,383         21,712         76,841       42,554
amortization
Income tax benefit         (28)           -              (37)         -
Interest expense           22,581         9,269          41,267       17,977
EBITDA                     79,027         105,832        100,670      141,853
Income attributable to
non-controlling            (1,810)        (1,061)        (3,179)      (2,597)
interests^(2)
Non-controlling
interest depreciation,     (1,121)        -              (1,971)      -
amortization and
interest^(3)
Adjustment for cash
flow from investment in    2,272          (117)          2,032        787
joint ventures
Loss on asset              1,519          -              1,519        -
disposition
Non-cash (gain) loss on    (24,263)       (64,741)       (10,544)     (54,045)
derivatives
Acquisition costs          18,370         -              18,900       -
Premium expense on         3,745          3,984          7,020        7,736
derivative instruments
Unrecognized economic      1,126          -              1,126        -
impact of acquisitions
Loss on early              19             -              26,601       -
termination of debt
Other non-cash             7,428          5,163          11,844       6,413
losses^(4)
Adjusted EBITDA            86,312         49,060         154,018      100,147
Interest expense           (22,581)       (9,269)        (41,267)     (17,977)
Amortization of            1,739          1,130          3,283        2,295
deferred finance costs
Premium expense on         (3,745)        (3,984)        (7,020)      (7,736)
derivative instruments
Other costs                -              (161)          -            (195)
Maintenance capital        (3,713)        (4,000)        (7,527)      (8,510)
expenditures^(5)
Distributable Cash Flow $  58,012      $  32,776      $  101,487    $ 68,024
(1) EBITDA, Adjusted EBITDA and Distributable Cash Flow are non-GAAP
(generally accepted accounting principles) financial measures under the rules
of the Securities and Exchange Commission. Management of the Partnership
believes EBITDA, Adjusted EBITDA and Distributable Cash Flow provide
additional information for evaluating the Partnership's ability to make
distributions to its common unit holders and the general partner, among other
things. These measures are widely-used by commercial banks, investment
bankers, rating agencies and investors in evaluating performance relative to
peers and pre-set performance standards. Adjusted EBITDA is also similar to
the Consolidated EBITDA calculation utilized for the Partnership's financial
covenants under its credit facility, with the exception that Adjusted EBITDA
includes non-cash items specifically excluded under the credit facility.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of
financial performance under GAAP and, accordingly, should not be considered in
isolation or as a substitute for net income, operating income, or cash flows
from operating activities in accordance with GAAP
(2) Represents Anadarko Petroleum Corporation's ("Anadarko" – NYSE: APC)
non-controlling interest in the operating results of Atlas Pipeline
Mid-Continent WestOk, LLC ("WestOK") and Atlas Pipeline Mid-Continent WestTex,
LLC ("WestTX"); and MarkWest's non-controlling interest in Centrahoma
(3) Represents the depreciation, amortization and interest expense included
in income attributable to non-controlling interest for MarkWest's interest in
Centrahoma
(4) Includes the non-cash impact of commodity price movements on pipeline
linefill inventory, non-cash compensation and minimum volume adjustments on
certain producer throughput contracts
(5) Net of non-controlling interest maintenance capital of $135 thousand and
$176 thousand for the three and six months ended June 30, 2013, respectively





ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights^(1)


                        Three Months Ended June 30,  Six Months Ended June 30,
                                            Percent                    Percent
                        2013       2012              2013      2012
                                            Change                    Change
Pricing (unhedged):
Weighted Average Market
Prices:
NGL price per gallon –  $  0.75    $  0.70  7.1 %    $  0.79   $ 0.82  (3.7)%
Conway hub
NGL price per gallon –     0.80       0.94  (14.9)%     0.83     1.06  (21.7)%
Mt. Belvieu hub
Natural gas sales
($/MCF):
Velma                   3.88       2.04     90.2%    3.53      2.29    54.1%
WestOK                  3.84       2.09     83.7%    3.54      2.30    53.9%
WestTX                  3.74       1.85     102.2%   3.45      2.18    58.3%
Weighted average        3.82       2.01     90.0%    3.59      2.26    58.8%
NGL sales ($/Gallon):
Arkoma                  0.66       -        -        0.69      -       -
Velma                   0.72       0.71     1.4 %    0.75      0.82    (8.5)%
WestOK                  0.96       0.79     21.5 %   0.97      0.85    14.1 %
WestTX                  0.86       0.88     (2.3)%   0.89      1.03    (13.6)%
Weighted average        0.84       0.80     5.0 %    0.84      0.92    (8.7)%
Condensate sales
($/barrel):
Arkoma                  81.18      -        -        84.79     -       -
Velma                   93.32      93.69    (0.4)%   93.36     98.52   (5.2)%
WestOK                  84.53      85.41    (1.0)%   84.10     90.00   (6.6)%
WestTX                  93.96      86.17    9.0 %    91.97     91.11   0.9 %
Weighted average        89.15      87.00    2.5 %    88.09     91.95   (4.2)%





ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights^(1)


                      Three Months Ended June 30,  Six Months Ended June 30,
                                          Percent                      Percent
                      2013       2012              2013       2012
                                          Change                       Change
Volumes:
Arkoma system^(2):
Gathered gas volume   283,238    -        -        272,047    -        -
(MCFD)
Processed gas         202,113    -        -        201,709    -        -
volume^(3) (MCFD)
Residue gas volume    208,163    -        -        208,004    -        -
(MCFD)
Processed NGL volume  25,590     -        -        22,736     -        -
(BPD)
Condensate volume     152        -        -        156        -        -
(BPD)
SouthTX system:
Gathered gas volume   122,245    -        -        122,245    -        -
(MCFD)
Processed gas         121,338    -        -        121,338    -        -
volume^(3) (MCFD)
Residue gas volume    96,606     -        -        96,606     -        -
(MCFD)
Processed NGL volume  15,041     -        -        15,041     -        -
(BPD)
Condensate volume     65         -        -        65         -        -
(BPD)
Velma system:
Gathered gas volume   139,736    136,553  2.3%     135,276    132,888  1.8%
(MCFD)
Processed gas         132,699    129,070  2.8%     129,058    125,987  2.4%
volume^(3) (MCFD)
Residue gas volume    111,487    106,424  4.8%     106,888    103,380  3.4%
(MCFD)
Processed NGL volume  16,201     14,220   13.9%    15,105     13,931   8.4%
(BPD)
Condensate volume     384        434      (11.5)%  394        499      (21.0)%
(BPD)
WestOK system:
Gathered gas volume   506,487    336,377  50.6%    479,577    315,787  51.9%
(MCFD)
Processed gas         483,504    315,753  53.1%    454,628    297,529  52.8%
volume^(3) (MCFD)
Residue gas volume    444,670    291,225  52.7%    420,815    271,582  54.9%
(MCFD)
Processed NGL volume  22,233     14,379   54.6%    19,258     14,220   35.4%
(BPD)
Condensate volume     1,949      1,209    61.2%    1,959      1,307    49.9%
(BPD)
WestTX system^(2):
Gathered gas volume   352,865    267,395  32.0%    332,829    256,867  29.6%
(MCFD)
Processed gas         313,504    236,213  32.7%    297,220    233,359  27.4%
volume^(3) (MCFD)
Residue gas volume    229,777    164,593  39.6%    219,889    162,308  35.5%
(MCFD)
Processed NGL volume  39,901     32,755   21.8%    36,591     32,928   11.1%
(BPD)
Condensate volume     1,993      1,941    2.7%     1,516      1,440    5.3%
(BPD)
Barnett system:
 Gathered gas       20,081     23,988   (16.3)%  20,737     23,988   (13.6)%
volumes (MCFD)
Tennessee system:
 Gathered gas       8,166      8,348    (2.2)%   8,826      8,286    6.5%
volumes (MCFD)
West Texas LPG
Partnership^(2)
 Average NGL     252,886    243,708  3.8%     248,779    243,013  2.4%
volumes (BPD)
Consolidated Volumes:
 Gathered gas     1,432,818  772,661  85.4%    1,371,537  737,816  85.9%
volume (MCFD)
 Processed gas    1,253,158  681,036  84.0%    1,203,953  656,875  83.3%
volume (MCFD)
 Residue gas      1,090,703  562,242  94.0%    1,052,202  537,270  95.8%
volume (MCFD)
 Processed NGL    118,966    61,354   93.9%    108,731    61,079   78.0%
volume (BPD)
 Condensate       4,543      3,584    26.8%    4,090      3,246    26.0%
volume (BPD)
(1) "MCF" represents thousand cubic feet; "MCFD" represents thousand cubic
feet per day; "BPD" represents barrels per day
(2) Operating data for the Arkoma and WestTX systems and for West Texas LPG
Partnership represents 100% of operating activity
(3) Processed gas volumes include volumes offloaded and processed by third
parties as well as volumes bypassed and delivered as residue gas



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of July 31, 2013)
Note: The natural gas, natural gas liquid and condensate price risk management
positions shown below represent the contracts in place through December 31,
2016. APL's price risk management position in its entirety will be disclosed
in the Partnership's Form 10-Q. NGL contracts are traded at Mt. Belvieu unless
otherwise disclosed.
SWAP CONTRACTS
NATURAL GAS LIQUIDS HEDGES
Production Period   Purchased /Sold   Commodity       Gallons      Avg. Fixed
                                                                   Price
3Q13                Sold              Propane         12,726,000   1.25
3Q13                Sold              Propane -       1,260,000    1.06
                                      Conway
4Q13                Sold              Propane         16,254,000   1.20
4Q13                Sold              Propane -       1,260,000    1.06
                                      Conway
4Q13                Sold              Normal Butane   1,260,000    1.31
1Q14                Sold              Propane         15,624,000   0.98
1Q14                Sold              Iso Butane      1,260,000    1.26
1Q14                Sold              Normal Butane   1,260,000    1.28
1Q14                Sold              Natural         1,890,000    2.01
                                      Gasoline
2Q14                Sold              Propane         12,852,000   0.94
2Q14                Sold              Iso Butane      2,520,000    1.25
2Q14                Sold              Normal Butane   2,520,000    1.38
2Q14                Sold              Natural         3,780,000    1.93
                                      Gasoline
3Q14                Sold              Propane         8,190,000    0.97
3Q14                Sold              Iso Butane      1,260,000    1.26
3Q14                Sold              Normal Butane   1,260,000    1.50
3Q14                Sold              Natural         3,150,000    1.93
                                      Gasoline
4Q14                Sold              Propane         8,190,000    0.98
4Q14                Sold              Iso Butane      1,260,000    1.26
4Q14                Sold              Normal Butane   1,260,000    1.53
4Q14                Sold              Natural         3,150,000    1.93
                                      Gasoline
1Q15                Sold              Propane         7,686,000    0.95
1Q15                Sold              Natural         2,142,000    1.91
                                      Gasoline
2Q15                Sold              Propane         8,064,000    0.92
2Q15                Sold              Natural         630,000      1.97
                                      Gasoline
3Q15                Sold              Propane         378,000      0.93
3Q15                Sold              Natural         630,000      1.97
                                      Gasoline
4Q15                Sold              Propane         3,528,000    0.96
4Q15                Sold              Natural         630,000      1.97
                                      Gasoline





ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of July 31, 2013)
SWAP CONTRACTS
CONDENSATE HEDGES
Production Period  Purchased /Sold Commodity   Barrels   Avg. Fixed Price
3Q13               Sold            Crude Oil   78,000    97.08
4Q13               Sold            Crude Oil   75,000    96.66
1Q14               Sold            Crude Oil   93,000    95.45
2Q14               Sold            Crude Oil   99,000    93.29
3Q14               Sold            Crude Oil   75,000    89.86
4Q14               Sold            Crude Oil   45,000    88.16
1Q15               Sold            Crude Oil   15,000    85.13
2Q15               Sold            Crude Oil   15,000    85.13
3Q15               Sold            Crude Oil   15,000    85.13
4Q15               Sold            Crude Oil   15,000    85.13
NATURAL GAS HEDGES
Production Period  Purchased /Sold Commodity   MMBTUs    Avg. Fixed Price
3Q13               Sold            Natural Gas 1,530,000 3.62
4Q13               Sold            Natural Gas 1,570,000 3.75
1Q14               Sold            Natural Gas 1,650,000 3.97
2Q14               Sold            Natural Gas 2,650,000 3.89
3Q14               Sold            Natural Gas 4,000,000 3.95
4Q14               Sold            Natural Gas 4,300,000 4.08
1Q15               Sold            Natural Gas 3,865,000 4.30
2Q15               Sold            Natural Gas 3,865,000 4.17
3Q15               Sold            Natural Gas 3,865,000 4.20
4Q15               Sold            Natural Gas 3,565,000 4.27
1Q16               Sold            Natural Gas 1,500,000 4.45
2Q16               Sold            Natural Gas 750,000   4.36
3Q16               Sold            Natural Gas 750,000   4.36
4Q16               Sold            Natural Gas 750,000   4.36



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of July 31, 2013)
OPTION CONTRACTS
NGL OPTIONS
Production Period Purchased/Sold Type Commodity       Gallons   Avg. Strike
                                                                Price
3Q13              Purchased      Put  Normal Butane   3,528,000 1.6440
3Q13              Purchased      Put  Iso Butane      1,512,000 1.6637
3Q13              Purchased      Put  Natural         6,300,000 2.0901
                                      Gasoline
4Q13              Purchased      Put  Normal Butane   3,780,000 1.6613
4Q13              Purchased      Put  Iso Butane      1,512,000 1.6622
4Q13              Purchased      Put  Natural         6,552,000 2.0933
                                      Gasoline
1Q14              Purchased      Put  Iso Butane      1,260,000 1.2225
2Q14              Purchased      Put  Propane         630,000   0.8880
3Q14              Purchased      Put  Propane         630,000   0.8975
4Q14              Purchased      Put  Propane         630,000   0.9200
3Q15              Purchased      Put  Propane         1,260,000 0.8825
CRUDE OPTIONS
Production Period Purchased/Sold Type Commodity       Barrels   Avg. Strike
                                                                Price
3Q13              Purchased      Put  Crude Oil       72,000    100.1000
4Q13              Purchased      Put  Crude Oil       75,000    100.1000
1Q14              Purchased      Put  Crude Oil       181,500   100.9690
2Q14              Purchased      Put  Crude Oil       60,000    88.9100
3Q14              Purchased      Put  Crude Oil       90,000    89.9133
4Q14              Purchased      Put  Crude Oil       117,000   91.5692
1Q15              Purchased      Put  Crude Oil       45,000    91.3333
2Q15              Purchased      Put  Crude Oil       75,000    89.4900
3Q15              Purchased      Put  Crude Oil       75,000    88.5900
4Q15              Purchased      Put  Crude Oil       75,000    88.1500
NATURAL GAS
OPTIONS
Production Period Purchased/Sold Type Commodity       MMBTUs    Avg. Strike
                                                                Price
2Q 2014           Purchased      Put  Natural Gas     300,000   4.10
3Q 2014           Purchased      Put  Natural Gas     300,000   4.15



Contact: Matthew Skelly
VP – Investor Relations
1845 Walnut Street
Philadelphia, PA 19103
(877) 280-2857
(215) 561-5692 (facsimile)

SOURCE Atlas Pipeline Partners, L.P.

Website: http://www.atlaspipeline.com
 
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