Add
ATLS to Portfolio
Set Alert
Email to a
Friend
| |||
|
|
Quotes & Info
|
| ATLS > SEC Filings for ATLS > Form 10-Q on 9-Aug-2012 | All Recent SEC Filings |
9-Aug-2012
Quarterly Report
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, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).
At June 30, 2012, our operations primarily consisted of our ownership interests in the following entities:
• Atlas Resource Partners, L.P. ("ARP"), 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. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At June 30, 2012, we owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 63.7% limited partner interest in ARP (see "Subsequent Events");
• Atlas Pipeline Partners, L.P. ("APL"), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At June 30, 2012, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.5% common limited partner interest; and
• Lightfoot Capital Partners, LP ("Lightfoot LP") and Lightfoot Capital Partners GP, LLC ("Lightfoot GP"), the general partner of Lightfoot L.P. (collectively, "Lightfoot"), entities which incubate new master limited partnerships ("MLPs") and invest in existing MLPs. At June 30, 2012, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.
In February 2012, the board of directors of our General Partner ("the Board") approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of our natural gas and oil development and production assets and the partnership management business to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to our unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.
FINANCIAL PRESENTATION
Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at June 30, 2012 except for ARP and APL, which we control. Due to the structure of our ownership interests in ARP and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners' capital on our consolidated combined balance sheets. Throughout this section, when we refer to "our" consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of ARP and APL, adjusted for non-controlling interests in ARP and APL. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements.
On February 17, 2011, we acquired certain producing natural gas and oil properties, a partnership management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the "Transferred Business") from Atlas Energy, Inc. ("AEI"), the former owner of our general partner. Our management determined that the acquisition of the Transferred Business 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 based upon their fair values 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 on our consolidated combined balance sheet. 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 to 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;
• 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 the six months ended June 30, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business' historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.
SUBSEQUENT EVENTS
Cash Distribution. On July 17, 2012, we declared a cash distribution of $0.25 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $12.8 million distribution will be paid on August 17, 2012 to unitholders of record at the close of business on August 7, 2012.
APL Cash Distribution. On July 17, 2012, APL declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $32.3 million distribution, including $2.2 million to us, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.
ARP's Acquisition of Titan Operating, L.L.C. On July 25, 2012, ARP acquired certain proved reserves and associated assets in the Barnett Shale from Titan Operating, L.L.C. ("Titan") for 3.8 million of ARP's common units and 3.8 million newly-created convertible Class B preferred units (which have a collective value of $193.2 million, based upon the fair value of the units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. Also, ARP entered into an amendment to its senior secured revolving credit facility (see "ARP Credit Facility") on July 26, 2012 to increase the borrowing base from $250.0 million to $310.0 million.
ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the Securities and Exchange Commission by January 25, 2013 to register the resale of the common units issued on the acquisition closing date and those issuable upon conversion of the preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. If ARP does not meet the aforementioned deadline for the registration statement to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement determined based on a per unit price of $26.03, or $1.0 million, for the first 30-day period after March 31, 2013, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period.
RECENT DEVELOPMENTS
ARP Cash Distribution. On June 28, 2012, the ARP declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $13.2 million distribution, including $0.3 million to us, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on July 12, 2012.
APL's Expansion Project. In June 2012, APL completed construction of, and started processing through, a 60 MMCFD cryogenic facility at its Velma gas plant, increasing capacity at Velma to 160 million cubic feet per day ("MMCFD"). This expansion supports APL's long-term fee-based agreement with XTO Energy, Inc., a subsidiary of ExxonMobil, to provide natural gas gathering and processing services for up to an incremental 60 MMCFD from the Woodford Shale.
APL's Acquisition of Gas Gathering Systems and Related Assets. In June 2012, APL acquired a gas gathering system and related assets in the Barnett Shale play in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system consists of 19 miles of gathering pipeline that is used to facilitate gathering some of the newly acquired production for ARP. In February 2012, APL acquired a gas gathering system and related assets, within their WestOK system, for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. In connection with this acquisition, APL received assignment of gas purchase agreements for gas currently gathered on the acquired system. APL accounted for these acquisitions as business combinations.
New Credit Facility. In May 2012, we entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. Our obligations under the credit facility are secured by substantially all of our assets, including our ownership interests in APL and ARP. Additionally, our obligations under the credit facility may be guaranteed by future subsidiaries. The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter (see "Credit Facility").
APL's Amended Credit Facility. In May 2012, APL entered into an amendment to their revolving credit facility agreement that increased the facility from $450.0 million to $600.0 million (see "APL Credit Facility").
ARP's Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, ARP 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 ARP's credit facility and $119.5 million of net proceeds from the sale of 6.0 million of ARP's common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of our executives. ARP's common units issued in the private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the Securities and Exchange Commission by October 30, 2012 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by December 31, 2012. If ARP does not meet the aforementioned deadline for the common units to
be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement, or $0.6 million, for the first 30-day period after December 31, 2012, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period.
ARP's Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and natural gas liquids 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 ARP's revolving credit facility (see "ARP Credit Facility"). Concurrent with the closing of the acquisition, ARP entered into a participation and development agreement with Equal for future drilling in the Mississippi Lime play and both parties can contribute acreage to the joint venture through the establishment of an area of mutual interest closely surrounding Equal's existing acreage position.
CONTRACTUAL REVENUE ARRANGEMENTS
Atlas Resources
Natural Gas. ARP markets the majority of its 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 ARP's 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. ARP sells 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. ARP sells its NGL production at the prevailing spot market price for NGLs.
ARP does 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. ARP generally has funded a portion of its drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for its drilling activities, its 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, ARP receives the following fees:
• Well construction and completion. For each well that is drilled by an investment partnership, ARP receives 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, ARP receives a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the partnerships, the net fee that ARP receives is reduced by its proportionate interest in the well;
• Well services. Each partnership pays ARP a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because ARP coinvests in the partnerships, the net fee that ARP receives is reduced by its proportionate interest in the wells; and
• Gathering. Each royalty owner, partnership and certain other working interest owners pay ARP 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, ARP has with a third-party gathering system, which gathers the majority of our natural gas, ARP 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 its 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%.
Atlas Pipeline
APL's principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Variables that affect its revenue are:
• the volumes of natural gas APL gathers and processes, which in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;
• the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;
• the NGL and BTU content of the gas that is gathered and processed;
• the contract terms with each producer; and
• the efficiency of APL's gathering systems and processing plants.
Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas.
GENERAL TRENDS AND OUTLOOK
Atlas Resource
The areas in which ARP operates 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 ARP anticipates continued high levels of exploration and production activities over the long-term in the areas in which it operates, 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.
ARP's future gas and oil reserves, production, cash flow, its ability to make payments on its revolving credit facility and its ability to make distributions to its unitholders, including us, depend on ARP's success in producing its current reserves efficiently, developing its existing acreage and acquiring additional proved reserves economically. ARP faces 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. ARP attempts to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than it produces.
Atlas Pipeline
APL faces competition in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of APL's competitors operate as master limited partnerships and enjoy a cost of capital comparable to, and in some cases lower than, its own. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL's. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. APL management believes the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. APL management believes offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows it to compete more effectively for new natural gas supplies in its regions of operations.
As a result of APL's Percentage of Proceeds ("POP") and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil. APL management believes future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL management generally expects NGL prices to follow changes in crude oil prices over the long term, which management believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.
RESULTS OF OPERATIONS
GAS AND OIL PRODUCTION
Production Profile. Currently, ARP has focused its natural gas and oil production operations in various shale plays throughout the United States. As part of our agreement with AEI to acquire the Transferred Business on February 17, 2011, ARP has certain agreements which restrict its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through June 30, 2012, ARP has 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 ARP 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 ARP established a position following its acquisition of assets from Carrizo in April 2012 (see "Recent Developments");
• the Mississippi Lime play in northwestern Oklahoma, an oil and natural gas liquids rich area, in which ARP acquired a 50% joint venture interest in 14,500 net undeveloped acres in April 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 . . .
|
|