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ARP > SEC Filings for ARP > Form 10-Q on 6-Nov-2012All Recent SEC Filings

Show all filings for ATLAS RESOURCE PARTNERS, L.P.

Form 10-Q for ATLAS RESOURCE PARTNERS, L.P.


6-Nov-2012

Quarterly Report


ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in "Item 1A. Risk Factors", in our annual report on Form 10-K for the year ended December 31, 2011. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

BUSINESS OVERVIEW

We are a publicly-traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas and oil, with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance a portion of our natural gas and oil production activities.

At September 30, 2012, Atlas Energy, L.P. ("ATLS"), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of our general partner Class A units and incentive distribution rights through which it manages and effectively controls us, and an approximate 51.5% limited partnership ownership interest (20,960,000 limited partner units) in us.

We were formed in October 2011 to own and operate substantially all of ATLS' exploration and production assets (the "Atlas Energy E&P Operations"), which were transferred to us on March 5, 2012. In February 2012, the board of directors of ATLS' general partner approved the distribution of approximately 5.24 million of our common units which were distributed on March 13, 2012 to ATLS' unitholders using a ratio of 0.1021 of our limited partner units for each of ATLS' common units owned on the record date of February 28, 2012. The distribution of our limited partner units represented approximately 20% of the common limited partner units outstanding.

On February 17, 2011, ATLS acquired certain assets and liabilities (the "Transferred Business") from Atlas Energy, Inc. ("AEI"), the former owner of ATLS' general partner. These assets principally included the following exploration and production assets which were included within Atlas Energy's E&P Operations:

AEI's investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we fund a portion of our natural gas and oil well drilling;

proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee; and

certain producing natural gas and oil properties, upon which we are developers and producers.

FINANCIAL PRESENTATION

Our consolidated combined balance sheet at September 30, 2012, the statement of operations for the three months ended September 30, 2012, and the portion of the consolidated combined statement of operations for the nine months ended September 30, 2012 subsequent to the transfer of assets on March 5, 2012 include our accounts and our wholly-owned subsidiaries. Our combined balance sheet at December 31, 2011, the portion of the consolidated combined statements of operations for the nine months ended September 30, 2012 prior to the transfer of assets on March 5, 2012 and the combined statement of operations for the three and nine months ended September 30, 2011 were derived from the separate records maintained by ATLS and may not necessarily be indicative of the conditions that would have existed if we had been operated as an unaffiliated entity. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated combined balance sheets and related consolidated combined statements of operations. Such estimates included allocations made from the historical accounting records of ATLS, based on management's best estimates, in order to derive our financial statements for the periods presented prior to the transfer of assets. Actual balances and results could be different from those estimates.


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Upon the acquisition of the Transferred Business on February 17, 2011, ATLS' management determined that the acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners' capital/equity. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners' capital/equity;

Retrospectively adjusted our consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

Adjusted the presentation of our consolidated combined statements of operations for any date prior to February 17, 2011 to reflect the results of operations attributable to the Transferred Business as a reduction of net income (loss) to determine income (loss) attributable to common limited partners and the general partner. The Transferred Business' historical financial statements prior to the date of acquisition reflect an allocation of general and administrative expenses determined by AEI to the underlying business segments, including the Transferred Business. We have reviewed AEI's general and administrative expense allocation methodology, which is based on the relative total assets of AEI and the Transferred Business, for the Transferred Business' historical financial statements prior to the date of acquisition and believe the methodology is reasonable and reflects the approximate general and administrative costs of our underlying business segments.

SUBSEQUENT EVENTS

Cash Distribution. On October 25, 2012, we declared a cash distribution of $0.43 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2012. The $17.5 million distribution, including $0.4 million and $1.7 million to the general partner and preferred limited partners, respectively, will be paid on November 14, 2012 to unitholders of record at the close of business on November 5, 2012.

RECENT DEVELOPMENTS

Acquisition of Titan Operating, L.L.C. On July 25, 2012, we completed the acquisition of Titan Operating, L.L.C. ("Titan") in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had a collective value of $193.2 million, based upon the closing price of our publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see "Issuance of Units"). Through the acquisition of Titan, we acquired interests in approximately 52 proved developed natural gas wells and approximately 250 Bcfe of proved reserves and 700 Bcfe of proved, probable and possible reserves and associated assets in the Barnett Shale, located in the Bend Arch - Fort Worth Basin in North Texas. Also, we entered into an amendment to our senior secured revolving credit facility on July 26, 2012 to increase the borrowing base from $250.0 million to $310.0 million. The cash paid at closing was funded through borrowings under our credit facility (see "Credit Facility"). The common units and preferred units were issued and sold in a private transaction exempt from registration under
Section 4(2) of the Securities Act of 1933, as amended (the "Securities Act") (see "Issuance of Units").

Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, we acquired certain oil and natural gas assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; "Carrizo") for approximately $187.0 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch - Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. The purchase price was funded through borrowing under our credit


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facility and $119.5 million of net proceeds from the sale of 6.0 million of our common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of our executives. The common units were issued in a private transaction exempt from registration under Section 4 (2) of the Securities Act (see "Issuance of Units").

Equal Acquisition. In April 2012, we acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. ("Equal") (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under our revolving credit facility (see "Credit Facility"). Concurrent with the purchase of acreage, we and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. We served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, we acquired Equal's remaining 50% interest in the undeveloped acres, as well as approximately 8 Mmcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. The additional acquisition was subject to certain post-closing adjustments and funded with available borrowings under our revolving credit facility (see "Credit Facility"). As a result of our acquisition of Equal's remaining interest in the undeveloped acres, the existing joint venture agreement between us and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by us.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the NYMEX spot market price; Barnett Shale, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced at the prevailing spot market price in each region.

Natural Gas Liquids. Natural gas liquids ("NGL's") are extracted from the natural gas stream by processing and fractionation plants enabling the remaining "dry" gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell our NGL production at the prevailing spot market price for NGLs.

We do not have delivery commitments for fixed and determinable quantities of natural gas, oil or NGLs in any future periods under existing contracts or agreements.

Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, we receive the following fees:

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well;

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well;

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the wells; and

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.


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GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The areas in which we operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic prices. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our revolving credit facility and our ability to make distributions to our unitholders, including ATLS, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas and oil production operations in various shale plays throughout the United States. As part of ATLS' agreement with AEI to acquire the Transferred Business on February 17, 2011, we have certain agreements which restrict our ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through September 30, 2012, we have established production positions in the following areas:

the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas; the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region; and the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone;

the Barnett Shale in the Bend Arch Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which we established a position following our acquisitions of assets from Carrizo and Titan during 2012 (see "Recent Developments");

the Mississippi Lime play in northwestern Oklahoma, an oil and natural gas liquids rich area, in which we established a position following our acquisitions from Equal during 2012 (see "Recent Developments");

the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and

the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale.


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The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three and nine months ended September 30, 2012 and 2011:

                                          Three Months  Ended          Nine Months  Ended
                                             September 30,                September 30,
                                          2012             2011        2012           2011

 Gross wells drilled:
 Appalachia                                     8              9            22            12
 Barnett                                        9             -              9            -
 Mississippi Lime                               2             -              4            -
 Niobrara                                      -              33            51            50

                                               19             42            86            62


 Our share of gross wells drilled(1):
 Appalachia                                     2              2             6             3
 Barnett                                        8             -              8            -
 Mississippi Lime                              -              -              1            -
 Niobrara                                      -               6            15            12

                                               10              8            30            15


 Gross wells turned in line:
 Appalachia                                    13             -             46             1
 Barnett                                        3             -              3            -
 Mississippi Lime                               2             -              2            -
 New Albany/Antrim                             -              -             -             13
 Niobrara                                      26              7            98            37

                                               44              7           149            51

(1) Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in our investment partnerships.

Production Volumes. The following table presents our total net natural gas, oil, and natural gas liquids production volumes and production per day for the three and nine months ended September 30, 2012 and 2011:

                                        Three Months  Ended          Nine Months  Ended
                                           September 30,                September 30,
                                         2012           2011          2012          2011
   Production:(1)(2)
   Appalachia:(3)
   Natural gas (MMcf)                      3,642         2,492           9,661       7,689
   Oil (000's Bbls)                           25            27              79          81
   Natural gas liquids (000's Bbls)           38            38             116         122

   Total (MMcfe)                           4,022         2,880          10,832       8,910

   Barnett:(4)
   Natural gas (MMcf)                      4,055            -            5,830          -
   Oil (000's Bbls)                           -             -               -           -
   Natural gas liquids (000's Bbls)           60            -               63          -

   Total (MMcfe)                           4,417            -            6,210          -

   Mississippi Lime:(5)
   Natural gas (MMcf)                         59            -               59          -
   Oil (000's Bbls)                           -             -               -           -
   Natural gas liquids (000's Bbls)           -             -               -           -

   Total (MMcfe)                              59            -               59          -

   New Albany/Antrim:
   Natural gas (MMcf)                        286           283             837         866

   Total (MMcfe)                             286           283             837         866

   Niobrara:
   Natural gas (MMcf)                         73            42             198          95

   Total (MMcfe)                              73            42             198          95

   Total:
   Natural gas (MMcf)                      8,115         2,818          16,586       8,651
   Oil (000's Bbls)                           25            27              80          81
   Natural gas liquids (000's Bbls)           98            38             179         122

   Total (MMcfe)                           8,857         3,206          18,136       9,871


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         Production per day: (1)(2)
         Appalachia:(3)
         Natural gas (Mcfd)             39,583       27,088       35,260       28,166
         Oil (Bpd)                         275          294          290          297
         Natural gas liquids (Bpd)         414          408          422          448

         Total (Mcfed)                  43,716       31,304       39,533       32,637

         Barnett:(4)
         Natural gas (Mcfd)             49,440           -        21,278           -
         Oil (Bpd)                           2           -             1           -
         Natural gas liquids (Bpd)         865           -           230           -

         Total (Mcfed)                  54,642           -        22,663           -

         Mississippi Lime:(5)
         Natural gas (Mcfd)              7,391           -           216           -
         Oil (Bpd)                          -            -            -            -
         Natural gas liquids (Bpd)          -            -            -            -

         Total (Mcfed)                   7,391           -           216           -

         New Albany/Antrim:
         Natural gas (Mcfd)              3,111        3,081        3,054        3,172

         Total (Mcfed)                   3,111        3,081        3,054        3,172

         Niobrara:
         Natural gas (Mcfd)                792          461          723          349

         Total (Mcfed)                     792          461          723          349

         Total: (4)(5)
         Natural gas (Mcfd)             88,208       30,629       60,531       31,687
         Oil (Bpd)                         277          294          291          297
         Natural gas liquids (Bpd)       1,067          408          652          448

         Total (Mcfed)                  96,275       34,845       66,189       36,158

(1) Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership's proportionate net revenue interest in these wells.

(2) "MMcf" represents million cubic feet; "MMcfe" represent million cubic feet equivalents; "Mcfd" represents thousand cubic feet per day; "Mcfed" represents thousand cubic feet equivalents per day; and "Bbls" and "Bpd" represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately six Mcf's to one barrel.

(3) Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

(4) Volumetric production per day for Barnett for the three months ended September 30, 2012 includes production per day associated with the Titan operational assets for the 68-day period from July 25, 2012, the date of acquisition, through September 30, 2012. Total Barnett production per day for the nine months ended September 30, 2012 represents Barnett volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

(5) Volumetric production per day for Mississippi Lime for the three months ended September 30, 2012 includes production per day associated with the acquisition of the remaining 50% interest in Equal's operational assets for . . .

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