SOURCE: Atlas Pipeline Partners, L.P.

November 01, 2007 21:27 ET

Atlas Pipeline Partners, L.P. Reports Record Adjusted EBITDA of $66.4 Million for the Third Quarter 2007

PHILADELPHIA, PA--(Marketwire - November 1, 2007) - Atlas Pipeline Partners, L.P. (NYSE: APL) (the "Partnership") today reported record adjusted earnings before interest, income taxes, depreciation and amortization ("EBITDA"), a non-GAAP (generally accepted accounting principles) measure, of $66.4 million for the third quarter 2007 compared with $20.6 million for the prior year third quarter. Distributable cash flow totaled $45.7 million for the third quarter 2007 compared to distributable cash flow of $14.6 million for the comparable prior year quarter. The Partnership's distribution coverage ratio for the third quarter 2007 was approximately 1.2x. The quarter-over-quarter results were favorably impacted by contributions from the Chaney Dell and Midkiff/Benedum systems, which the Partnership acquired in July 2007, and higher volumes on its other systems. System-wide volumes were approximately 1.2 billion cubic feet per day ("bcfd") for the third quarter 2007 compared with 0.6 bcfd for the prior year comparable quarter, an increase of approximately 83%. Increased throughput volume on the NOARK interstate pipeline system ("NOARK") and an increase in Appalachia gathered natural gas also contributed to the aggregate growth in system volumes. On a GAAP basis, the Partnership recognized a net loss of $24.5 million for the third quarter 2007, largely related to one-time, non-cash charges totaling $45.2 million, primarily related to non-cash compensation expense, non-cash derivative expense and accelerated amortization of deferred financing costs. The non-cash compensation expense resulted from incentive compensation agreements with certain key employees located in our Mid-Continent headquarters in Tulsa, OK. These awards are based upon the accomplishment of certain predetermined performance targets through December 2008 related to various acquisitions, including the acquisition of the Chaney Dell and Midkiff/Benedum systems. The compensation expense amount recorded for these common unit awards reflects management's current estimate with regard to the achievement of the predetermined performance targets. The accelerated amortization of deferred finance costs was associated with the Partnership's replacement of its credit facility in July 2007 with a new $300.0 million revolving credit facility in connection with its acquisition of the Chaney Dell and Midkiff/Benedum systems.

On July 27, 2007, for a payment of approximately $1.9 billion, the Partnership acquired control of Anadarko Petroleum Corporation's (NYSE: APC) ("Anadarko") 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the "Assets"). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, and the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems. In connection with this acquisition, the Partnership reached an agreement with Pioneer Natural Resources Company (NYSE: PXD) ("Pioneer"), which held a right of first refusal to purchase the Midkiff/Benedum system. Pioneer provides approximately 50% of the natural gas processed by the Midkiff/Benedum system under its obligation to connect its wells within a certain distance of the Midkiff/Benedum system. Under this new agreement, Pioneer waived its right of first refusal and extended its obligation to the Midkiff/Benedum system an additional 10 years through 2022. The Partnership granted to Pioneer, which currently holds a 27.2% interest in the Midkiff/Benedum system, an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system one year after the closing of the Partnership's acquisition of Anadarko's interest, and up to an additional 7.5% interest two years after the closing of the Partnership's acquisition of Anadarko's interest. If the options are fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. The Partnership will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

The Partnership funded the purchase price of the acquisition in part from a private placement of 25.6 million common limited partner units, generating gross proceeds of $1.125 billion. Atlas Pipeline Holdings, L.P. (NYSE: AHD) ("Atlas Holdings"), the parent of the Partnership's general partner, purchased 3.8 million of the 25.6 million common limited partner units issued by the Partnership. The Partnership funded the remaining purchase price with an $830.0 million senior secured term loan which matures in July 2014 and a partial advance against a new $300.0 million senior secured revolving credit facility which matures in July 2013. Atlas Holdings, which owns all of the incentive distribution rights in the Partnership, has agreed to allocate a portion of its future incentive distribution rights back to the Partnership in connection with the Anadarko acquisition, namely up to $5.0 million of incentive distribution rights per quarter to the Partnership through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

The Partnership declared a record quarterly cash distribution for the third quarter 2007 of $0.91 per common limited partner unit on October 23, 2007, an increase of $0.06 per unit or 7.1% from the comparable prior year period. The third quarter 2007 distribution will be paid on November 14, 2007 to all unitholders of record as of November 7, 2007. Total distributions declared for the third quarter 2007 of $39.7 million represent a 162% increase from the prior year comparable quarter. The Partnership established distribution guidance at a range of $1.78 to $1.85 per common limited partner unit for the second half of 2007 and $3.80 to $4.00 per common limited partner unit for 2008, while also trending the targeted distribution coverage ratio towards 1.2x.

"The record results this quarter are truly gratifying, but I'm extremely hopeful that in this case the past is only prologue," stated Edward E. Cohen, Chairman and Chief Executive Officer of Atlas Pipeline. "When we next report, we will have the advantage of a full quarter incorporating our new acquisition and the further advantage, we expect, of a full integration of these operations into our system."

Segment Analysis

Mid-Continent

Excluding the effect of an $11.5 million derivative expense, the Mid-Continent segment recognized total revenue of $244.6 million for the third quarter 2007, an increase of $134.9 million from the prior year comparable quarter. This increase principally reflects the contribution from the acquisition of the Chaney Dell and Midkiff Benedum systems of $135.0 million and higher system volumes. Average gross natural gas processed volume from July 27, 2007, the date of acquisition, through September 30, 2007 was 250.0 MMcfd for the Chaney Dell system and 106.6 MMcfd for the Midkiff/Benedum system. There were 81 new wells connected to the Chaney Dell system during the third quarter 2007 and there were 59 new wells connected to the Midkiff/Benedum system for the same period. For the Elk City/Sweetwater system, average gross natural gas processed volume for the third quarter 2007 was 231.2 MMcfd, a 69.8% increase from the third quarter 2006. The Partnership connected 18 new wells to the Elk City/Sweetwater system during the third quarter 2007 compared with 13 new wells for the prior year comparable quarter. For the NOARK system, average Ozark Gas Transmission throughput volume was 325.7 MMcfd during the third quarter 2007, a 43.5% increase from the third quarter 2006. The Velma system's average processed natural gas volume of 62.0 MMcfd for the third quarter 2007 represented a 6.3% increase over the prior year comparable quarter. The Partnership connected 13 new wells to its Velma system during the third quarter 2007.

Appalachia

Total revenue for the Appalachia system was $9.1 million for the third quarter 2007 compared with $7.1 million for the third quarter 2006, an increase of $2.0 million due principally to higher throughput volume and higher realized transportation rates. Throughput volume increased to 71.9 MMcfd for the third quarter 2007 compared with 63.9 MMcfd for the third quarter 2006 resulting from the connection of new wells to the Appalachia gathering system. The Appalachia system's average transportation rate per thousand cubic feet ("mcf") was $1.32 for the third quarter 2007, a 10.9% increase from $1.19 per mcf for the prior year third quarter. During the third quarter 2007, 189 new wells were connected to the Appalachia gathering system compared with 149 new wells for the prior year comparable quarter, representing a 27% increase. Additionally, 252 wells were added to the Appalachia system during the third quarter 2007 due to the acquisition of a natural gas gathering and processing system in August 2007, which has a processing capacity of 10.0 MMcfd and was acquired for $6.1 million.

Corporate and Other

General and administrative expense, including amounts reimbursed to affiliates, increased $32.4 million to $37.8 million for the third quarter 2007 from $5.4 million for the third quarter 2006. This increase was primarily related to a $30.2 million increase in non-cash compensation expense arising from vesting of phantom and common unit awards and higher costs associated with managing our operations. Certain common unit awards of the Partnership are based upon the accomplishment of certain predetermined performance targets for consummated acquisitions, including the acquisition of the Chaney Dell and Midkiff/Benedum systems, through December 2008. The amount recorded for these common unit awards reflect management's current estimate with regard to the achievement of the predetermined performance targets. Depreciation and amortization increased $10.0 million to $16.2 million for the third quarter 2007 due primarily to the depreciation associated with the Chaney Dell and Midkiff/Benedum assets acquired by the Partnership in July 2007 and the Partnership's expansion capital expenditures incurred subsequent to the third quarter 2006, including the Sweetwater processing facility.

Interest expense increased to $24.0 million for the third quarter 2007, an increase of $18.3 million from the prior year third quarter. This increase was primarily related to interest associated with the Partnership's $830.0 million term loan, which was issued in July 2007 and partially funded its acquisition of the Chaney Dell and Midkiff/Benedum systems, additional borrowings under its credit facility to finance its expansion capital expenditures, and $5.0 million of accelerated amortization of deferred finance costs associated with the Partnership's replacement of its credit facility in July 2007 with a new $300.0 million revolving credit facility. At September 30, 2007, the Partnership had $1,158.0 million of total debt, including an $830.0 million term loan that matures in 2014, $294.4 million of senior unsecured notes that mature in 2015 and $33.5 million of outstanding borrowings under its $300.0 million credit facility.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's third quarter 2007 results on Friday, November 2, 2007 at 9:00 am ET by going to the Investor Relations section of the Partnership's website at www.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 11:00 am ET on Friday, November 2, 2007. To access the replay, dial 1-888-286-8010 and enter conference code 46464454.

Atlas Pipeline Partners, L.P. is active in the transmission, gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, Arkansas, northern and western Texas and the Texas panhandle, the Partnership owns and operates eight gas processing plants and a treating facility, as well as approximately 7,900 miles of active intrastate gas gathering pipeline and a 565-mile interstate natural gas pipeline. In Appalachia, it owns and operates approximately 1,600 miles of natural gas gathering pipelines in western Pennsylvania, western New York and eastern Ohio. For more information, visit our website at www.atlaspipelinepartners.com or contact bbegley@atlaspipelinepartners.com.

Atlas Pipeline Holdings, L.P. is a limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P., through which it owns a 2% general partner interest, all the incentive distribution rights and approximately 5.5 million common units of Atlas Pipeline Partners.

Atlas Energy Resources, LLC is an energy concern focused on the development and production of natural gas and, to a lesser extent, oil principally in the eastern United States. Atlas Energy sponsors and manages tax advantaged investment partnerships, in which it co-invests, to finance the exploration and development of its acreage in the Appalachian Basin and drills on its own account in the Antrim Shale of Michigan. For more information, visit Atlas Energy's website at www.atlasenergyresources.com or contact investor relations at bbegley@atlasamerica.com.

Atlas America, Inc. owns an approximate 64% limited partner interest in Atlas Pipeline Holdings, L.P. and an approximate 49% common unit interest and all of the Class A and management incentive interests in Atlas Energy Resources, LLC (NYSE: ATN). For more information, please visit our website at www.atlasamerica.com, or contact Investor Relations at bbegley@atlasamerica.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. Factors that could cause actual results to differ materially from expectations include financial performance, inability of the Partnership to successfully integrate the operations at the acquired systems, regulatory changes, changes in 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, reports on Form 8-K and annual reports on Form 10-K.


             ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
                           Financial Summary
                 (in thousands, except per unit amounts)

                             Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                            ----------------------  ----------------------
STATEMENTS OF OPERATIONS       2007        2006        2007        2006
                            ----------  ----------  ----------  ----------

Revenue:
  Natural gas and liquids   $  229,891  $   99,997  $  436,859  $  296,083
  Transportation,
   compression, and other
   fees - affiliates             8,495       6,951      24,673      22,659
  Transportation,
   compression, and other
   fees - third parties         12,948       6,726      33,374      20,882
  Other income (loss)           (9,034)      6,872     (39,654)      8,233
                            ----------  ----------  ----------  ----------
    Total revenue and other
     income (loss)             242,300     120,546     455,252     347,857
                            ----------  ----------  ----------  ----------

Costs and expenses:
  Natural gas and liquids      174,727      89,679     349,639     252,577
  Plant operating                9,108       3,853      18,153      11,006
  Transportation and
   compression                   3,555       2,714       9,877       7,639
  General and
   administrative               36,424       5,069      48,735      13,465
  Compensation
   reimbursement -
   affiliates                    1,392         378       2,820       1,983
  Depreciation and
   amortization                 16,176       6,152      29,381      16,685
  Interest                      24,040       5,700      38,126      18,191
  Minority interest              1,376           -       1,376         118
                            ----------  ----------  ----------  ----------
    Total costs and
     expenses                  266,798     113,545     498,107     321,664
                            ----------  ----------  ----------  ----------

Net income (loss)              (24,498)      7,001     (42,855)     26,193
Preferred unit dividend
 effect                              -           -      (3,756)          -
Preferred unit imputed
 dividend cost                    (624)       (627)     (1,858)     (1,262)
                            ----------  ----------  ----------  ----------
Net income (loss)
 attributable to common
 limited partners and the
 general partner            $  (25,122) $    6,374  $  (48,469) $   24,931
                            ==========  ==========  ==========  ==========

Allocation of net income
 (loss) attributable to
 common limited partners
 and the general partner:
  Common limited partners'
   interest                 $  (28,242) $    2,567  $  (58,854) $   13,664
  General partner's
   interest                      3,120       3,807      10,385      11,267
                            ----------  ----------  ----------  ----------
    Net income (loss)
     attributable to
     common limited
     partners and the
     general partner        $  (25,122) $    6,374  $  (48,469) $   24,931
                            ==========  ==========  ==========  ==========

Net income (loss)
 attributable to common
 limited partners per unit:
   Basic                    $    (0.90) $     0.20  $    (3.05) $     1.07
                            ==========  ==========  ==========  ==========
   Diluted                  $    (0.90) $     0.19  $    (3.05) $     1.05
                            ==========  ==========  ==========  ==========

Weighted average common
 limited partner units
 outstanding:
   Basic                        31,449      13,076      19,270      12,818
                            ==========  ==========  ==========  ==========
   Diluted                      31,449      13,248      19,270      12,975
                            ==========  ==========  ==========  ==========

Capital expenditure data:
  Maintenance capital
   expenditures             $    2,328  $      843  $    3,800  $    2,921
  Expansion capital
   expenditures                 47,937      25,088      89,860      58,822
                            ----------  ----------  ----------  ----------
    Total                   $   50,265  $   25,931  $   93,660  $   61,743
                            ==========  ==========  ==========  ==========



                                     September 30, December 31,
Balance Sheet Data (at period end):      2007          2006
                                     ------------- -------------
  Cash and cash equivalents          $      24,808 $       1,795
  Total assets                           2,807,871       786,884
  Total debt                             1,157,963       324,083
  Total partners' capital                1,422,482       379,134




                 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
                             Segment Information
                               (in thousands)


                             Three Months Ended       Nine Months Ended
                                September 30,           September 30,
                            ----------------------  ----------------------
                               2007        2006        2007        2006
                            ----------  ----------  ----------  ----------
Mid-Continent
-------------
  Revenue:
    Natural gas and liquids $  229,511  $   99,997  $  436,479  $  296,083
    Transportation,
     compression, and other
     fees                       12,793       6,707      33,183      20,817
    Other income (loss)         (9,133)      6,754     (39,918)      7,709
                            ----------  ----------  ----------  ----------
      Total revenue and
       other income (loss)     233,171     113,458     429,744     324,609
                            ----------  ----------  ----------  ----------

  Costs and expenses:
    Natural gas and liquids    174,471      89,679     349,383     252,577
    Plant operating              9,108       3,853      18,153      11,006
    Transportation and
     compression                 1,943       1,389       5,443       4,029
    General and
     administrative             34,806       3,590      43,506       9,753
    Depreciation and
     amortization               14,992       5,200      26,007      14,034
    Minority interest            1,376           -       1,376         118
                            ----------  ----------  ----------  ----------
      Total costs and
       expenses                236,696     103,711     443,868     291,517
                            ----------  ----------  ----------  ----------
  Segment profit (loss)     $   (3,525) $    9,747  $  (14,124) $   33,092
                            ==========  ==========  ==========  ==========

Appalachia
----------
  Revenue:
    Natural gas and liquids $      380  $        -  $      380  $        -
    Transportation,
     compression, and other
     fees - affiliates           8,494       6,951      24,673      22,659
    Transportation,
     compression, and other
     fees - third parties          156          19         191          65
    Other income                    99         118         264         524
                            ----------  ----------  ----------  ----------
      Total revenue and
       other income              9,129       7,088      25,508      23,248
                            ----------  ----------  ----------  ----------

  Costs and expenses:
    Natural gas and liquids        256           -         256           -
    Transportation and
     compression                 1,612       1,325       4,434       3,610
    General and
     administrative              1,505         929       4,025       2,848
    Depreciation and
     amortization                1,184         952       3,374       2,651
                            ----------  ----------  ----------  ----------
      Total costs and
       expenses                  4,557       3,206      12,089       9,109
                            ----------  ----------  ----------  ----------
  Segment profit            $    4,572  $    3,882  $   13,419  $   14,139
                            ==========  ==========  ==========  ==========

Reconciliation of segment
 profit (loss) to net
 income (loss):
-------------------------
  Segment profit (loss):
   Mid-Continent            $   (3,525) $    9,747  $  (14,124) $   33,092
   Appalachia                    4,572       3,882      13,419      14,139
                            ----------  ----------  ----------  ----------
     Total segment profit
      (loss)                     1,047      13,629        (705)     47,231
   Corporate general and
    administrative expense      (1,505)       (928)     (4,024)     (2,847)
   Interest expense            (24,040)     (5,700)    (38,126)    (18,191)
                            ----------  ----------  ----------  ----------
   Net income (loss)        $  (24,498) $    7,001  $  (42,855) $   26,193
                            ==========  ==========  ==========  ==========



             ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARES
                            (in thousands)

                             Three Months Ended       Nine Months Ended
                                September 30,           September 30,
                            ----------------------  ----------------------
                               2007        2006        2007        2006
                            ----------  ----------  ----------  ----------

Reconciliation of net
 income (loss) to adjusted
 net  income (loss):
  Net income (loss)         $  (24,498) $    7,001  $  (42,855) $   26,193
  Effect of prior period
   items (1)                         -           -           -       1,090
  Effect of certain items (2)        -       1,971           -      (1,596)
                            ----------  ----------  ----------  ----------
    Adjusted net income
     (loss)                 $  (24,498) $    8,972  $  (42,855) $   25,687
                            ==========  ==========  ==========  ==========

Reconciliation of net
 income (loss) to non-GAAP
 measures (3):
  Net income (loss)         $  (24,498) $    7,001  $  (42,855) $   26,193
  Depreciation and
   amortization                 16,176       6,152      29,381      16,685
  Interest expense              24,040       5,700      38,126      18,191
                            ----------  ----------  ----------  ----------
    EBITDA                      15,718      18,853      24,652      61,069
  Non-cash derivative
   expense (income)              8,430      (1,851)     39,256      (2,107)
  Non-cash compensation
   expense                      31,834       1,623      36,110       4,125
  Unrecognized economic
   impact of Anadarko
   acquisition (4)              10,423           -      10,423           -
  Effect of prior period
   items (1)                         -           -           -       1,090
  Effect of certain items (2)        -       1,971           -      (1,596)
                            ----------  ----------  ----------  ----------
    Adjusted EBITDA             66,405      20,596     110,441      62,581
  Interest expense             (24,040)     (5,700)    (38,126)    (18,191)
  Minority interest share
   of interest expense               -           -           -         938
  Amortization of deferred
   financing costs
   (included within
   interest expense)             5,622         548       6,690       1,753
  Maintenance capital
   expenditures                 (2,328)       (843)     (3,800)     (2,921)
                            ----------  ----------  ----------  ----------
    Distributable cash flow $   45,659  $   14,601  $   75,205  $   44,160
                            ==========  ==========  ==========  ==========


(1) During June 2006, the Partnership identified measurement reporting
    inaccuracies on three newly installed pipeline meters. To adjust for
    such inaccuracies, which related to natural gas volume gathered during
    the third and fourth quarters of 2005 and first quarter of 2006, the
    Partnership recorded an adjustment of $1.2 million during the second
    quarter of 2006 to increase natural gas and liquids cost of goods sold.
    If the $1.2 million adjustment had been recorded when the inaccuracies
    arose, reported net income would have been reduced by approximately
    2.7%, 8.3%, and 1.4% for the third quarter of 2005, fourth quarter of
    2005, and first quarter of 2006, respectively. Management of the
    Partnership believes that the impact of these adjustments is immaterial
    to its current and prior financial statements.

(2) Includes the addback of $3.6 million of unfavorable revisions to
    previously estimated producer volumes, $0.8 million of estimated
    unrecoverable costs and loss of revenue as a result of the temporary
    outage at a Velma compressor station due to fire damage sustained, and
    $0.4 million of lower condensate revenue due to evaporation caused by
    unusually warm temperatures in the areas where the Partnership
    operates. These amounts are partially offset by a $2.7 million gain on
    sale of certain gathering pipelines in the Velma system.

(3) 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 that 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.
    EBITDA is also a financial measurement that, with certain negotiated
    adjustments, is utilized within the Partnership's financial covenants
    under its credit facility. EBITDA and distributable cash flow are not
    measures of financial performance under GAAP and, accordingly, should
    not be considered as a substitute for net income, operating income, or
    cash flows from operating activities in accordance with GAAP.

(4) The acquisition of the Chaney Dell and Midkiff/Benedum systems was
    consummated on July 27, 2007, although the acquisitions' effective date
    was July 1, 2007. As such, the Partnership receives the economic
    benefits of ownership of the assets as of July 1, 2007. However, in
    accordance with accounting regulations, the Partnership has only
    recorded the results of the acquired assets commencing on the closing
    date of the acquisition.



             ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARES
                       Operating Highlights

                             Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                            ----------------------- -----------------------
                               2007        2006        2007        2006
                            ----------- ----------- ----------- -----------
Mid-Continent - Velma System
----------------------------
  Natural Gas
    Gross natural gas
     gathered - mcfd(1)          63,757      62,113      62,531      61,641
    Gross natural gas
     processed - mcfd(1)         61,968      58,296      60,555      58,881
    Gross residue natural
     gas - mcfd(1)               49,502      45,724      47,487      46,042
  Natural Gas Liquids
    Gross NGL sales - bpd(1)      6,215       6,598       6,386       6,536
  Condensate
    Gross condensate sales
     - bpd(1)                       254         205         222         209

Mid-Continent - Elk
-------------------
 City/Sweetwater System
  Natural Gas
    Gross natural gas
     gathered - mcfd(1)         299,450     284,461     298,724     270,957
    Gross natural gas
     processed - mcfd(1)        231,152     136,101     224,521     134,169
    Gross residue natural
     gas - mcfd(1)              211,368     123,275     206,011     121,661
  Natural Gas Liquids
    Gross NGL sales - bpd(1)      9,782       6,049       9,351       6,016
  Condensate
    Gross condensate sales
     - bpd(1)                       143          59         228         125

Mid-Continent - Chaney Dell
 System(2)
---------------------------
  Natural Gas
    Gross natural gas
     gathered - mcfd(1)         255,649           -     255,649           -
    Gross natural gas
     processed - mcfd(1)        249,982           -     249,982           -
    Gross residue natural
     gas - mcfd(1)              222,508           -     222,508           -
  Natural Gas Liquids
    Gross NGL sales - bpd(1)     12,678           -      12,678           -
  Condensate
    Gross condensate sales
     - bpd(1)                       564           -         564           -

Mid-Continent -
 Midkiff/Benedum System(2)
--------------------------
  Natural Gas
    Gross natural gas
     gathered - mcfd(1)         150,061           -     150,061           -
    Gross natural gas
     processed - mcfd(1)        106,601           -     106,601           -
    Gross residue natural
     gas - mcfd(1)               93,859           -      93,859           -
  Natural Gas Liquids
    Gross NGL sales - bpd(1)     20,702           -      20,702           -
  Condensate
    Gross condensate sales
     - bpd(1)                     1,754           -       1,754           -

Mid-Continent - NOARK system
----------------------------
  Ozark Gas Transmission
   throughput - mcfd(1)         325,652     226,962     311,562     236,331

Appalachia
----------
  Throughput - mcfd(1)           71,876      63,909      66,888      61,473
  Average transportation
   rate per mcf(1)          $      1.32 $      1.19 $      1.36 $      1.35



(1) "Mcf" represents thousand cubic feet; "Mcfd" represents thousand cubic
    feet per day; "Bpd" represents barrels per day.
(2) Volumetric data for the Chaney Dell System and Midkiff/Benedum system
    for the three and nine months ended September 30, 2007 represents
    volumes recorded for the 66-day period from July 27, 2007, the date of
    acquisition, through September 30, 2007.



                  ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
                   Current Mid-Continent Segment Hedge Positions
                           (as of November 1, 2007)


Natural Gas Liquids Sales

 Production Period                              Average
 Ended December 31,             Volumes        Fixed Price
-------------------           ------------     ------------
                                (gallons)      (per gallon)
       2007                    42,651,000       $    0.893
       2008                    61,362,000            0.706
       2009                     8,568,000            0.746



Crude Oil Sales Options (associated with NGL volume)

                                  Associated     Average
Ended December 31,     Crude         NGL          Crude
Production Period      Volume       Volume     Strike Price   Option Type
------------------   ------------ ------------ ------------  --------------
                       (barrels)    (gallons)  (per barrel)
      2007                390,000   25,789,680 $      60.00  Puts purchased
      2007                390,000   25,789,680        75.15  Calls sold
      2008              3,744,600  249,257,484        60.00  Puts purchased
      2008              3,744,600  249,257,484        79.38  Calls sold
      2009              4,752,000  324,233,280        60.00  Puts purchased
      2009              4,752,000  324,233,280        78.68  Calls sold
      2010              2,413,500  169,282,890        60.00  Puts purchased
      2010              2,413,500  169,282,890        77.28  Calls sold




Natural Gas Sales

Production Period                                Average
Ended December 31,              Volumes         Fixed Price
-------------------          -------------     -------------
                              (mmbtu)(1)       (per mmbtu)(1)
      2007                     1,449,000       $     8.197
      2008                     5,484,000             8.795
      2009                     5,724,000             8.611
      2009                     2,820,000             8.635

Natural Gas Basis Sales

Production Period                                Average
Ended December 31,              Volumes         Fixed Price
-------------------          -------------     -------------
                               (mmbtu)(1)      (per mmbtu)(1)
      2007                      1,449,000        $   (0.729)
      2008                      5,484,000            (0.727)
      2009                      5,724,000            (0.513)
      2010                      2,820,000            (0.572)

Natural Gas Purchases

Production Period                                Average
Ended December 31,              Volumes         Fixed Price
-------------------          -------------     -------------
                                (mmbtu)(1)     (per mmbtu)(1)
      2007                       3,909,000       $     8.633(2)
      2008                      16,260,000             8.923(3)
      2009                      15,564,000             8.680
      2010                       7,200,000             8.635




              ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
              Current Mid-Continent Segment Hedge Positions
                       (as of November 1, 2007)

Natural Gas Basis Purchases

Production Period                               Average
Ended December 31,             Volumes        Fixed Price
-------------------         --------------    -------------
                               (mmbtu)(1)     (per mmbtu)(1)
      2007                      3,909,000       $   (1.048)
      2008                     15,276,000           (1.186)
      2009                     14,820,000           (0.686)
      2010                      7,200,000           (0.560)



Crude Oil Sales

Production Period                              Average
Ended December 31,             Volumes        Fixed Price
-------------------         --------------   --------------
                              (barrels)       (per barrel)
      2007                      17,600     $     56.477
      2008                      65,400           59.424
      2009                      33,000           62.700



Crude Oil Sales Options

Production Period                         Average
Ended December 31,        Volumes       Strike Price       Option Type
-------------------    --------------   --------------     ------------
                          (barrels)      (per barrel)
     2007                   189,300           60.000    Puts purchased
     2007                   189,300           75.363    Calls sold
     2008                   691,800           60.000    Puts purchased
     2008                   691,800           78.004    Calls sold
     2009                   738,000           60.000    Puts purchased
     2009                   738,000           80.622    Calls sold
     2010                   402,000           60.000    Puts purchased
     2010                   402,000           79.341    Calls sold
     2011                    30,000           60.000    Puts purchased
     2011                    30,000           74.500    Calls sold
     2012                    30,000           60.000    Puts purchased
     2012                    30,000           73.900    Calls sold


(1) Mmbtu represents million British Thermal Units.
(2) Includes the Partnership's premium received from its sale of an option
    for it to sell 1,200,000 mmbtu of natural gas at an average price of
    $17.00 per mmbtu for the year ended December 31, 2007.
(3) Includes the Partnership's premium received from its sale of an option
    for it to sell 936,000 mmbtu of natural gas for the year ended December
    31, 2008 at $15.50 per mmbtu.

Contact Information

  • Contact:
    Brian J. Begley
    Vice President, Investor Relations
    1845 Walnut Street
    Philadelphia, PA 19103
    (215) 546-5005
    (215) 561-5692 (facsimile)