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Last updated on April 19, 2014 at 8:45 EDT

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

April 29, 2013

- Adjusted EBITDA for first quarter 2013 was $67.7 million, a 32% increase year-over-year

PHILADELPHIA, April 29, 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 $67.7 million for the first quarter of 2013, driven primarily by a continued increase in volumes across the Partnership’s gathering and processing systems. Processed natural gas volumes averaged 1,033 million cubic feet per day (“MMCFD”), a 63% increase over the first quarter of 2012. Distributable Cash Flow was $43.5 million for the first quarter of 2013, or $0.67 per average common limited partner unit, compared to $35.2 million for the prior year’s first quarter. The Partnership recognized a net loss of $27.5 million for the first quarter of 2013, which included a $26.6 million loss on the early retirement of the Partnership’s 8.75% Senior Notes due 2018, compared with net income of $6.5 million for the prior year first 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 April 24, 2013, the Partnership declared a distribution for the first quarter of 2013 of $0.59 per common limited partner unit to holders of record on May 8, 2013, which will be paid on May 15, 2013. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.04x on a fully diluted basis for the first quarter of 2013, excluding the most recent common equity issuance that closed on April 23, 2013.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, “The year has already provided for some very exciting announcements for Atlas Pipeline. It is with great pleasure that, since the end of the quarter, we have announced a major entry into the Eagle Ford with the $1 billion announced purchase of TEAK Midstream. This is a major win for the Partnership, adding tremendous expected future growth while reducing APL cash flow volatility through diversity and significant fixed fee business. Since the end of the quarter, we have also brought the Driver expansion online in West Texas and are receiving NGL takeaway capacity relief on our two largest systems, which will lead to more NGL’s being produced and more future cash flow to the Partnership. Our first quarter of 2013 came in line with expectations, aside from some weather disruptions, which can be a normal occurrence during winter months. More importantly, looking forward, our business and future opportunities have never looked better after all of the recent positive developments we have just announced. I would like to thank our investors who have supported us as we grow, and assure all of us our best days still lay ahead.”

Significant Developments after First Quarter of 2013

Since the end of the reporting period, the Partnership has publicly announced several developments that are expected to have a significant impact on the Distributable Cash Flow of APL for 2013-2014. On April 15, 2013, Atlas Pipeline announced that the 200 MMCFD Driver plant has come online at the WestTX facility, increasing capacity from 255 MMCFD to 455 MMCFD. In addition to the expansion at WestTX, APL also announced the addition of further NGL takeaway capacity to deliver incremental natural gas liquids from its WestOK and WestTX processing systems. These connections will eliminate the near-term constraints on our NGL production at these systems and better utilize the Waynoka II and Driver expansions that were brought in service in September 2012 and April 2013, respectively.

Additionally, on April 16, 2013, the Partnership announced the acquisition of TEAK Midstream, L.L.C. (“TEAK”), a private midstream company in the prolific Eagle Ford shale. TEAK currently has 200 MMCFD in processing capacity with 200 MMCFD of additional capacity expected in 2014 and potentially an additional 200 MMCFD processing facility to be added in 2015. The cash flow of TEAK is approximately 80% fixed-fee, which will serve to greatly reduce the commodity sensitivity of the Partnership’s overall cash flows upon build-out and utilization of the system. Please refer to the Partnership’s press release from April 16, 2013 (“Atlas Pipeline Partners, L.P. To Acquire Eagle Ford Midstream Business For $1 Billion From TEAK Midstream”) for more information regarding the transaction.

* * *

Updated 2013-2014 Forecasted Guidance

Upon the announcement of the acquisition of TEAK, APL initiated guidance for 2014, including forecasted Adjusted EBITDA of between $450 to $500 million and anticipated distributions of between $2.75 and $2.85 per limited partner unit. The Partnership is now updating Adjusted EBITDA for 2013 to between $360 million and $400 million based on current commodity pricing curves for natural gas, natural gas liquids, and crude oil. The resulting forecasted Distributable Cash Flow for 2013 is expected to range from $230 million to $270 million based on the same assumptions. Based on the Partnership’s distribution coverage targets, the forecasted distributions for 2013 remain between $2.50 and $2.60 per limited partner unit for the calendar year. The Partnership expects growth capital expenditures for the year to total approximately $450 million, based on previously announced expansion projects, including the now completed Driver plant and anticipated phase one of the Stonewall plant, as well as new infrastructure and projected well connections to support further volume growth on our existing and systems, including TEAK. It is important to note that the range of guidance for 2013 is based on information that has been publicly announced to date. Management will address the future outlook of the Partnership on the earnings conference call tomorrow morning as well as discuss recent developments since the end of the first quarter.

These forecasted amounts are based on various assumptions, including, among others, the Partnership’s expected cost and timing for completion of its announced capital expenditure program, timing of incremental volumes on its gathering and processing systems, known contract structures, scheduled maintenance of facilities, including those of third-parties that impact the Partnership’s operations, estimated interest rates, and budgeted operating and general administrative costs. Management does not forecast certain items, including GAAP revenues, depreciation, amortization, and non-cash changes in derivatives, and therefore is unable to provide forecasted Net Income, a comparable GAAP measure, for the periods presented. The reconciling items between these non-GAAP measures and Net Income are expected to be similar to those for the current periods presented and are not expected to be significant to the Partnership’s cash flows.

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $453.7 million as of March 31, 2013. Total debt outstanding was $1,318.9 million at March 31, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $139.0 million. Based upon total debt outstanding at March 31, 2013, total leverage was approximately 4.6x for purposes of calculations under our revolving credit facility, and debt to total capital was 46%. The Partnership recently announced the closing of a follow-on common equity issuance totaling 11,845,000 common limited partner units, resulting in gross proceeds of $402.7 million which will be used to fund the acquisition of TEAK. The Partnership also expects to issue $400 million of mandatorily convertible Class D Preferred Units in connection with the closing of the TEAK acquisition.

* * *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2016. As of April 29, 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 75%, 58%, and 33% respectively, of associated margin value (exclusive of ethane). The Partnership has also begun to add to protection in 2016. The percentages do not include the TEAK acquisition, which has not closed as of the date of this press release. 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 April 29, 2013 is included in this release.

* * *

Operating Results

The Partnership continues to report record volumes, and with the addition of the Arkoma assets, is now processing, on average, over 1.0 billion cubic feet per day of natural gas per day. Gross margin from operations was $91.1 million for the first quarter 2013, compared to $69.1 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 and Velma systems, as well as the newly acquired Arkoma system, and was partially offset by lower NGL prices. The gross margin for the quarter does not include approximately $1.6 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $0.8 million realized derivative settlement losses excluded from gross margin in the first quarter of 2012.

WestTX System

The WestTX system’s average natural gas processed volume was 280.8 MMCFD for the first quarter 2013, compared to 230.5 MMCFD for first quarter of 2012. Increased volumes are primarily due to increased production in the Spraberry and Wolfberry formations of the Permian basin, including an increase in the number of horizontally drilled wells by our producer customers. Average NGL production volumes were 33,245 barrels per day (“BPD”) for the first quarter 2013, a 0.4% increase from first quarter 2012. The Partnership expects processed volumes on this system to continue to increase as residue gas and NGL take-away constraints have been removed and producers continue to pursue their drilling plans over the coming years. The construction of the previously announced Driver plant, which increases processing capacity by 200 MMCFD, was completed and placed into service on April 12, 2013 and will allow for more efficient processing and delivery of natural gas and NGLs going forward.

WestOK System

The WestOK system had average natural gas processed volume of 425.4 MMCFD for the first quarter, a 52.3% increase from first quarter 2012. Average NGL production was 16,251 BPD for the first quarter 2013, a 15.6% increase from first quarter 2012, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012. First quarter 2013 results were negatively impacted by certain weather events in western Oklahoma which caused the loss of power and the shut-in of significant volumes for approximately 10 days in late February and early March. The Partnership estimates that the financial impact for this period was between $2 to $3 million in Adjusted EBITDA. The Partnership recently announced 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. This pipeline will allow the Partnership to process and deliver incremental NGL volumes from the WestOK system, including full production from the Waynoka I and Waynoka II facilities.

Velma System

The Velma system’s average natural gas processed volume was 125.4 MMCFD for the first quarter 2013, a 2.0% increase from first 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 13,997 BPD for the first quarter 2013, up approximately 2.6% compared to first quarter 2012, due to the increased processed volumes. In June 2012, the Partnership completed the previously announced plans to expand the Velma system by adding a 60 MMCFD cryogenic plant (the “V-60 plant”), which supports the additional volumes from XTO Energy, Inc (“XTO”). Volumes on the Velma system were greater than the fourth quarter of 2012 primarily due to XTO returning gas to V-60 during the period.

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 201.3 MMCFD and produced 20,555 BPD of NGLs during the first quarter of 2013. The Arkoma system has total gross name-plate processing capacity of 220 MMCFD, including the 120 MMCFD Tupelo plant which the Partnership owns 100%. The remaining processing capacity is owned by Centrahoma.

* * *

Corporate and Other

Net of deferred financing costs, interest expense increased to $17.1 million for the first quarter of 2013, up 34.2% as compared with the first quarter of 2012. This increase was due to financing the Partnership’s capital expenditure program during 2012 and 2013, including the issuance of senior unsecured notes in September and December 2012, as well as the February 2013 issuance of new 5.875% senior unsecured notes due 2023. These new senior unsecured notes were issued in connection with the redemption of the Partnership’s 8.75% Senior Notes due 2018, which resulted in a loss on the early termination of debt totaling $26.6 million in the first quarter 2013.

* * *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s first quarter 2013 results on Tuesday, April 30, 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, April 30, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 32722721.

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, northern and western Texas, and Tennessee, APL owns and operates 13 active gas processing plants, 18 gas treating facilities, as well as approximately 10,100 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 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 9% limited partner interest. Additionally, Atlas Energy owns all of the general partner Class A units and incentive distribution rights and an approximate 43% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. For more information, please visit the Partnership’s 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

                                                                                                                                                                                                                                                                                        March 31,
                                                                                                                                                                                                                                                                                        ---------

                                                                                                                                                                                                                                                                             2013                 2012
                                                                                                                                                                                                                                                                             ----

    Revenue:

    Natural gas and liquids                                                                                                                                                                                                                                                         $383,848               $289,225

    Transportation, processing and other fees(2)                                                                                                                                                                                                                           32,725               12,681

    Derivative loss, net                                                                                                                                                                                                                                                 (12,083)             (12,035)

    Other income, net                                                                                                                                                                                                                                                       3,422                2,415

    Total revenue and other income, net                                                                                                                                                                                                                                   407,912              292,286
                                                                                                                                                                                                                                                                          -------              -------

    Costs and expenses:

    Natural gas and liquids                                                                                                                                                                                                                                               325,540              233,105

    Plant operating                                                                                                                                                                                                                                                        21,271               13,881

    Transportation and compression                                                                                                                                                                                                                                            588                  264

    General and administrative(3)                                                                                                                                                                                                                                           9,414                8,967

    General and administrative - non-cash unit-based compensation(3)                                                                                                                                                                                                        4,384                  978

    Other costs                                                                                                                                                                                                                                                               530                  (34)

    Depreciation and amortization                                                                                                                                                                                                                                          30,458               20,842

    Interest                                                                                                                                                                                                                                                               18,686                8,708
                                                                                                                                                                                                                                                                           ------                -----

    Total costs and expenses                                                                                                                                                                                                                                              410,871              286,711
                                                                                                                                                                                                                                                                          -------              -------

    Equity income in joint venture                                                                                                                                                                                                                                          2,040                  896

    Loss on early extermination of debt                                                                                                                                                                                                                                  (26,582)             ?

    Income (loss) from continuing operations, before tax                                                                                                                                                                                                                 (27,501)                6,471

    Income tax benefit                                                                                                                                                                                                                                                         (9)            ?

    Net income (loss)                                                                                                                                                                                                                                                    (27,492)                6,471

    Income attributable to non-controlling interests                                                                                                                                                                                                                       (1,369)              (1,536)

    Net income attributable to common limited partners and the general partner                                                                                                                                                                                                      $(28,861)                $4,935
                                                                                                                                                                                                                                                                                    ========                 ======

    Net income (loss) attributable to common limited partners per unit:

    Basic and diluted:                                                                                                                                                                                                                                                                $(0.48)                 $0.06
                                                                                                                                                                                                                                                                                      ======                  =====

    Weighted average common limited partner units (basic)                                                                                                                                                                                                                  64,646               53,620
                                                                                                                                                                                                                                                                           ======               ======

    Weighted average common limited partner units (diluted)                                                                                                                                                                                                                64,646               54,013
                                                                                                                                                                                                                                                                           ======               ======

    (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

                          March 31,
                          ---------

                                    2013                              2012
                                    ----                              ----

    Summary Cash
     Flow Data:

    Net cash
     provided by
     (used in):

    Operating
     activities                                              $34,856       $42,747

    Investing
     activities                                             (107,990)      (98,276)

    Financing
     activities                                               77,997        55,529

    Capital
     Expenditure
     Data:

    Maintenance
     capital
     expenditures                                             $3,855        $4,510

    Expansion
     capital
     expenditures                                            104,661        76,657

    Acquisitions                          ?                                 17,235

    Total                                                   $108,516       $98,402
                                                            ========       =======



                                         ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                                             Condensed Consolidated Balance Sheets

                                                   (unaudited; in thousands)

    ASSETS                                                            March 31,                    December 31,
                                                                                                           2012
                                                                           2013
                                                                           ----

    Current assets:

    Cash and cash equivalents                                                               $8,261                  $3,398

    Other current assets                                                                   216,853                 216,677

    Total current assets                                                                   225,114                 220,075

    Property, plant and equipment, net                                                   2,299,967               2,200,381

    Intangible assets, net                                                                 502,071                 518,645

    Investment in joint ventures                                                            86,242                  86,002

    Other assets, net                                                                       41,036                  40,535

                                                                                        $3,154,430              $3,065,638
                                                                                        ==========              ==========

    LIABILITIES AND EQUITY

    Current liabilities                                                                   $252,059                $253,519

    Long-term debt, less current portion                                                 1,310,051               1,169,083

    Deferred income taxes, net                                                              30,249                  30,258

    Other long-term liability                                                                7,283                   6,370

    Total partners' capital                                                              1,487,942               1,539,177

    Non-controlling interest                                                                66,846                  67,231
                                                                                            ------                  ------

    Total equity                                                                         1,554,788               1,606,408

                                                                                        $3,154,430              $3,065,638
                                                                                        ==========              ==========



                                                   ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                                                         Reconciliation of Non-GAAP Measures

                                                              (unaudited; in thousands)

                                                                                                                                                          Three Months Ended

                                                                                                                                                              March 31,
                                                                                                                                                              ---------

                                                                                                                                                  2013             2012
                                                                                                                                                  ----             ----

    Reconciliation of net income to other non-GAAP
     measures(1):

    Net income                                                                                                                                           $(27,492)           $6,471

    Income attributable to non-controlling interests(2)                                                                                                    (1,369)          (1,536)

    Depreciation and amortization                                                                                                                          30,458            20,842

    Income tax benefit                                                                                                                                         (9)          ?

    Non-controlling interest depreciation, amortization
     and interest(3)                                                                                                                                         (850)

    Interest expense                                                                                                                                       18,686             8,708

    EBITDA                                                                                                                                                 19,424            34,485

    Adjustment for cash flow from investment in joint
     ventures                                                                                                                                                (240)              904

    Non-cash loss on derivatives                                                                                                                           13,719            10,696

    Successful acquisition costs                                                                                                                              530           ?

    Premium expense on derivative instruments                                                                                                               3,275             3,752

    Loss on early termination of debt                                                                                                                      26,582           ?

    Other non-cash losses(4)                                                                                                                                4,416             1,250

    Adjusted EBITDA                                                                                                                                        67,706            51,087

    Interest expense                                                                                                                                      (18,686)          (8,708)

    Amortization of deferred financing costs                                                                                                                1,544             1,165

    Premium expense on derivative instruments                                                                                                              (3,275)          (3,752)

    Other costs                                                                                                                                         ?                       (34)

    Maintenance capital expenditures                                                                                                                       (3,814)          (4,510)
                                                                                                                                                           ------            ------

    Distributable Cash Flow                                                                                                                               $43,475           $35,248
                                                                                                                                                          =======           =======

    (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 unitholders 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 (i) EBITDA from the discontinued operations related to the sale of the Partnership's 49% interest in Laurel
     Mountain; and (ii) other 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 and non-cash compensation


                     ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                            Unaudited Operating Highlights(1)

                                     Three Months Ended March 31,
                                   ----------------------------

                                  2013                  2012             Percent
                                                                         Change
                                                                         ------

    Pricing
     (unhedged):

    Mid-Continent
     Weighted
     Average Prices:

    NGL
     price
     per
     gallon
     -
     Conway
     hub                                  $0.83                      $0.93         (10.8)%

    NGL price per
     gallon - Mt.
     Belvieu hub                           0.85                       1.18         (28.0)%

    Natural gas
     sales ($/MCF):

    Velma                         3.17                  2.55          24.3%

    WestOK                        3.20                  2.56          25.0%

    WestTX                        3.12                  2.51          24.3%

     Weighted
     Average                      3.17                  2.54          24.8%

    NGL sales
     ($/Gallon):

    Arkoma                        0.70                     -                     -

    Velma                         0.75                  0.93        (19.4)%

    WestOK                        0.98                  0.91           7.7%

    WestTX                        0.93                  1.17        (20.5)%

     Weighted
     Average                      0.90                  1.03        (12.6)%

    Condensate sales
     ($/Barrel):

    Arkoma                       87.92                     -                     -

    Velma                        93.39                102.22         (8.6)%

    WestOK                       83.67                 93.95        (10.9)%

    WestTX                       88.02                101.38        (13.2)%

     Weighted
     Average                     86.00                 97.44        (11.7)%


                                                                    ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                                                                           Unaudited Operating Highlights(1)

                                                                                                                  Three Months Ended March 31,
                                                                                                                ----------------------------

                                                                                                                 2013                                  2012 Percent
                                                                                                                                                            Change
                                                                                                                                                            ------

    Volumes:

    Arkoma system:

    Gathered gas volume (MCFD)                                                                                260,732                                     -              -

    Processed gas volume(2) (MCFD)                                                                            201,301                                     -              -

    Residue gas volume (MCFD)                                                                                 207,844                                     -              -

    Processed NGL volume (BPD)                                                                                 20,555                                     -              -

    Condensate volume (BPD)                                                                                       158                                     -              -

    Velma system:

    Gathered gas volume (MCFD)                                                                                130,767                               129,223            1.2%

    Processed gas volume(2) (MCFD)                                                                            125,377                               122,904            2.0%

    Residue gas volume (MCFD)                                                                                 102,238                               100,335            1.9%

    Processed NGL volume (BPD)                                                                                 13,997                                13,643            2.6%

    Condensate volume (BPD)                                                                                       405                                   564         (28.2)%

    WestOK system:

    Gathered gas volume (MCFD)                                                                                452,368                               295,198           53.2%

    Processed gas volume(2) (MCFD)                                                                            425,431                               279,305           52.3%

    Residue gas volume (MCFD)                                                                                 396,694                               251,940           57.5%

    Processed NGL volume (BPD)                                                                                 16,251                                14,062           15.6%

    Condensate volume (BPD)                                                                                     1,969                                 1,405           40.1%

    WestTX system(3):

    Gathered gas volume (MCFD)                                                                                312,571                               246,339           26.9%

    Processed gas volume(2) (MCFD)                                                                            280,756                               230,504           21.8%

    Residue gas volume (MCFD)                                                                                 209,891                               160,022           31.2%

    Processed NGL volume (BPD)                                                                                 33,245                                33,101            0.4%

    Condensate volume (BPD)                                                                                     1,033                                   939           10.0%

    Barnett system:

       Gathered gas volumes (MCFD)                                                                             21,401                                     -            100%

    Tennessee system:

       Gathered gas volumes (MCFD)                                                                              9,495                                 8,225           15.4%

    West Texas LPG Partnership(4)

          Average NGL volumes (BPD)                                                                           244,626                               242,318            1.0%

    Consolidated Volumes:

         Gathered gas volume (MCFD)                                                                         1,187,334                               678,985           74.9%

         Processed gas volume (MCFD)                                                                        1,032,865                               632,713           63.2%

         Residue gas volume (MCFD)                                                                            916,667                               512,297           78.9%

         Processed NGL volume (BPD)                                                                            84,048                                60,806           38.2%

         Condensate volume (BPD)                                                                                3,565                                 2,908           22.6%

    (1)     "MCF" represents thousand cubic feet; "MCFD" represents thousand cubic feet per day; "BPD" represents barrels per day

    (2)     Processed gas volumes include volumes offloaded and processed by third parties as well as volumes bypassed and delivered as residue gas

    (3)     Operating data for the WestTX system represents 100% of its operating activity

    (4)     Volume data for the West Texas LPG Partnership represents 100% of its operating activity for the calendar year

(
)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of April 29, 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
    ----------                 --------------- ---------        -------            ----------------

    2Q 2013                    Sold            Propane - Conway          1,260,000                  1.06

    2Q 2013                    Sold            Propane                  10,836,000                  1.27

    2Q 2013                    Sold            Isobutane                   630,000                  1.77

    2Q 2013                    Sold            Normal butane             1,260,000                  1.66

    3Q 2013                    Sold            Propane - Conway          1,260,000                  1.06

    3Q 2013                    Sold            Propane                  12,726,000                  1.25

    4Q 2013                    Sold            Propane - Conway          1,260,000                  1.06

    4Q 2013                    Sold            Propane                  12,222,000                  1.28

    1Q 2014                    Sold            Propane                   8,694,000                  1.00

    1Q 2014                    Sold            Natural gasoline          1,260,000                  2.08

    2Q 2014                    Sold            Propane                   8,442,000                  0.96

    2Q 2014                    Sold            Normal Butane             1,260,000                  1.50

    2Q 2014                    Sold            Natural gasoline          3,150,000                  1.94

    3Q 2014                    Sold            Propane                   8,190,000                  0.97

    3Q 2014                    Sold            Normal Butane             1,260,000                  1.50

    3Q 2014                    Sold            Natural gasoline          2,520,000                  1.94

    4Q 2014                    Sold            Propane                   8,190,000                  0.98

    4Q 2014                    Sold            Normal Butane             1,260,000                  1.53

    4Q 2014                    Sold            Natural gasoline          2,520,000                  1.95

    1Q 2015                    Sold            Propane                   7,686,000                  0.95

    1Q 2015                    Sold            Natural gasoline          2,142,000                  1.91

    2Q 2015                    Sold            Propane                   8,064,000                  0.92

    2Q 2015                    Sold            Natural gasoline            630,000                  1.97

    3Q 2015                    Sold            Propane                     378,000                  0.93

    3Q 2015                    Sold            Natural gasoline            630,000                  1.97

    4Q 2015                    Sold            Propane                   3,528,000                  0.96

    4Q 2015                    Sold            Natural gasoline            630,000                  1.97


                                         ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                                      Unaudited Current Commodity Risk Management Positions

                                                     (as of April 24, 2013)

    SWAP CONTRACTS

    CONDENSATE HEDGES
    -----------------

    Production Period Purchased /Sold                       Commodity                    Barrels        Avg. Fixed Price
    ----------------- ---------------                       ---------                    -------        ----------------

    2Q 2013           Sold                                  Crude                                99,000                  97.33

    3Q 2013           Sold                                  Crude                                78,000                  97.08

    4Q 2013           Sold                                  Crude                                75,000                  96.66

    1Q 2014           Sold                                  Crude                                93,000                  95.45

    2Q 2014           Sold                                  Crude                                90,000                  93.43

    3Q 2014           Sold                                  Crude                                75,000                  89.86

    4Q 2014           Sold                                  Crude                                45,000                  88.16

    1Q 2015           Sold                                  Crude                                15,000                  85.13

    2Q 2015           Sold                                  Crude                                15,000                  85.13

    3Q 2015           Sold                                  Crude                                15,000                  85.13

    4Q 2015           Sold                                  Crude                                15,000                  85.13


    NATURAL GAS HEDGES
    ------------------

    Production Period  Purchased /Sold Commodity   MMBTUs           Avg. Fixed Price
    -----------------  --------------- ---------   ------           ----------------

    2Q 2013            Sold            Natural gas          600,000                  3.43

    3Q 2013            Sold            Natural gas        1,100,000                  3.60

    4Q 2013            Sold            Natural gas        1,420,000                  3.69

    1Q 2014            Sold            Natural gas        1,500,000                  3.91

    2Q 2014            Sold            Natural gas        2,500,000                  3.87

    3Q 2014            Sold            Natural gas        4,000,000                  3.95

    4Q 2014            Sold            Natural gas        4,000,000                  4.05

    1Q 2015            Sold            Natural gas        3,100,000                  4.29

    2Q 2015            Sold            Natural gas        3,100,000                  4.13

    3Q 2015            Sold            Natural gas        3,100,000                  4.17

    4Q 2015            Sold            Natural gas        2,800,000                  4.26

    1Q 2016            Sold            Natural gas          300,000                  4.40

    2Q 2016            Sold            Natural gas          300,000                  4.40

    3Q 2016            Sold            Natural gas          300,000                  4.40

    4Q 2016            Sold            Natural gas          300,000                  4.40


                                        ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

                                     Unaudited Current Commodity Risk Management Positions

                                                    (as of April 24, 2013)

    OPTION CONTRACTS

    NGL OPTIONS
    -----------

    Production Period Purchased/Sold    Type              Commodity                        Gallons           Avg. Strike Price
    ----------------- --------------    ----              ---------                        -------           -----------------

    2Q 2013           Purchased         Put               Propane                                  1,260,000                   0.87

    2Q 2013           Purchased         Put               Isobutane                                  630,000                   1.72

    2Q 2013           Purchased         Put               Normal Butane                            1,638,000                   1.66

    2Q 2013           Purchased         Put               Natural Gasoline                         5,796,000                   2.10

    3Q 2013           Purchased         Put               Isobutane                                1,512,000                   1.66

    3Q 2013           Purchased         Put               Normal Butane                            3,528,000                   1.64

    3Q 2013           Purchased         Put               Natural Gasoline                         6,300,000                   2.09

    4Q 2013           Purchased         Put               Isobutane                                1,512,000                   1.66

    4Q 2013           Purchased         Put               Normal Butane                            3,780,000                   1.66

    4Q 2013           Purchased         Put               Natural Gasoline                         6,552,000                   2.09

    CRUDE OPTIONS
    -------------

    Production Period Purchased/Sold Type Commodity Barrels         Avg. Strike Price
    ----------------- -------------- ---- --------- -------         -----------------

    2Q 2013           Purchased      Put  Crude Oil          69,000                   100.10

    3Q 2013           Purchased      Put  Crude Oil          72,000                   100.10

    4Q 2013           Purchased      Put  Crude Oil          75,000                   100.10

    1Q 2014           Purchased      Put  Crude Oil         166,500                   101.86

    2Q 2014           Purchased      Put  Crude Oil          45,000                    88.18

    3Q 2014           Purchased      Put  Crude Oil          75,000                    89.68

    4Q 2014           Purchased      Put  Crude Oil         102,000                    91.64

    1Q 2015           Purchased      Put  Crude Oil          45,000                    91.33

    2Q 2015           Purchased      Put  Crude Oil          75,000                    89.49

    3Q 2015           Purchased      Put  Crude Oil          75,000                    88.59

    4Q 2015           Purchased      Put  Crude Oil          75,000                    88.15

    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.


Source: PR Newswire