Atlas Pipeline Partners, L.P. 10-Q 2010
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended June 30, 2010
For the transition period from to
Commission file number:1-4998
ATLAS PIPELINE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Registrants telephone number, including area code: (412) 262-2830
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The number of common units of the registrant outstanding on August 2, 2010 was 53,252,793.
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
ITEM 1. FINANCIAL STATEMENTS
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
FOR THE SIX MONTHS ENDED JUNE 30, 2010
(in thousands, except unit data)
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2010
NOTE 1 BASIS OF PRESENTATION
Atlas Pipeline Partners, L.P. (the Partnership) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the gathering and processing of natural gas. The Partnerships operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the Operating Partnership), a wholly-owned subsidiary of the Partnership. At June 30, 2010, Atlas Pipeline Partners GP, LLC (the General Partner), through its general partner interests in the Partnership and the Operating Partnership, owns a 1.9% general partner interest in the consolidated pipeline operations, through which it manages and effectively controls both the Partnership and the Operating Partnership. The remaining 98.1% ownership interest in the consolidated pipeline operations consists of limited partner interests. The General Partner also owns 5,754,253 common limited partner units in the Partnership and 15,000 $1,000 par value 12% cumulative Class B preferred limited partner units. At June 30, 2010, the Partnership had 53,217,452 common limited partnership units outstanding, including the 5,754,253 common units held by the General Partner, plus 15,000 $1,000 par value 12% cumulative Class B preferred limited partner units held by the General Partner and 8,000 $1,000 par value 12% cumulative Class C preferred limited partner units held by Atlas Energy, Inc and its affiliates (Atlas Energy), a publicly-traded company (NASDAQ: ATLS) (see Note 6).
On March 31, 2010, the Partnerships limited partnership agreement was amended to provide a temporary waiver of a capital contribution required for the General Partner to maintain its 2.0% general partner interest in the Partnership, relative to the January 2010 issuance of common units for warrants exercised. The General Partner will not be required to make such capital contribution until it has received aggregate distributions from the Partnership, sufficient to fund the required capital contribution. During this waiver period the General Partners general partner interest will be reduced by approximately 0.1% to 1.9% (see Note 5).
The General Partner is a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P. (AHD), a publicly-traded partnership (NYSE: AHD). Atlas Energy, at June 30, 2010, owned a 64.3% ownership interest in AHDs common units, and 1,112,000 of the Partnerships common limited partnership units, representing a 2.1% ownership interest in the Partnership, along with 8,000 $1,000 par value 12% cumulative Class C preferred limited partner units (see Note 6).
The majority of the natural gas that the Partnership and its affiliates, including Laurel Mountain Midstream, LLC (Laurel Mountain), gather in Appalachia is derived from wells operated by Atlas Energy. Laurel Mountain, which was formed in May 2009, is a joint venture between the Partnership and The Williams Companies, Inc. (NYSE: WMB) (Williams) in which the Partnership has a 49% ownership interest and Williams holds the remaining 51% ownership interest.
The Partnership has adjusted its consolidated financial statements and related footnote disclosures presented within this Form 10-Q from the amounts previously presented to reflect the Partnerships January 1, 2010 reclassification of a portion of its income, within its consolidated statements of operations, to Transportation, Processing and Other Fees for fee-based revenues which were previously reported within Natural Gas and Liquids. This reclassification was made in order to provide clarity between the revenue that is commodity based and the revenue that is fee-based.
The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2009 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K.
In managements opinion, all adjustments necessary for a fair presentation of the Partnerships financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the three and six month periods ended June 30, 2010 may not necessarily be indicative of the results of operations for the full year ending December 31, 2010. Certain amounts in the prior years consolidated financial statements have been reclassified to conform to the current year presentation.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In addition to matters discussed further within this note, a more thorough discussion of the Partnerships significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2009.
Principles of Consolidation and Non-Controlling Interest
The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and the Operating Partnerships wholly-owned and majority-owned subsidiaries. The General Partners interest in the Operating Partnership is reported as part of its overall 1.9% general partner interest in the Partnership. All material intercompany transactions have been eliminated.
The Partnerships consolidated financial statements also include its 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. The Partnership consolidates 100% of these joint ventures and reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests and as a component of partners capital on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Partnerships consolidated balance sheets.
The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (Pioneer). Due to the ownership of the Midkiff/Benedum system being in the form of an undivided interest, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system.
Equity Method Investments
The Partnerships consolidated financial statements include its 49% ownership interest in Laurel Mountain, a joint venture which owns and operates the Partnerships former Appalachia Basin natural gas gathering systems, excluding the Partnerships northeastern Tennessee operations. The Partnership accounts for its investment in the joint venture under the equity method of accounting. Under this method, the Partnership records its proportionate share of the joint ventures net income (loss) as equity income on its consolidated statements of operations.
Use of Estimates
The preparation of the Partnerships consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnerships consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. The Partnerships consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation
and amortization, asset impairment, the fair value of derivative instruments, the probability of forecasted transactions, the allocation of purchase price to the fair value of assets acquired and other items. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current months financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following months financial results. Management believes that the operating results presented represent actual results in all material respects (see -Revenue Recognition accounting policy for further description).
In evaluating the realizability of its accounts receivable, the Partnership performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers current creditworthiness, as determined by the Partnerships review of its customers credit information. The Partnership extends credit on an unsecured basis to many of its customers. At June 30, 2010 and December 31, 2009, the Partnership recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.
The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 7.4% and 5.8% for the three months ended June 30, 2010 and 2009, respectively, and 7.4% and 5.3% for the six months ended June 30, 2010 and 2009, respectively. The amount of interest capitalized was $0.3 million and $0.5 million for the three months ended June 30, 2010 and 2009, respectively, and $0.5 million and $1.9 million for the six months ended June 30, 2010 and 2009, respectively.
The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at June 30, 2010 and December 31, 2009 (dollars in thousands):
The Partnership amortizes intangible assets with finite useful lives over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, the Partnership will assess the useful
lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for the Partnerships customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for the Partnerships customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for managements estimate of whether these individual relationships will continue in excess or less than the average length. Amortization expense on intangible assets was $6.4 million for both the three month periods ended June 30, 2010 and 2009, and $12.8 million for both the six month periods ended June 30, 2010 and 2009. Amortization expense related to intangible assets is estimated to be as follows for each of the next five calendar years: 2010 to 2012 - $25.6 million per year; 2013 - $24.5 million; 2014 - $20.4 million.
Net Income (Loss) Per Common Unit
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, and net income (loss) attributable to the General Partners and the preferred unitholders interests. The General Partners interest in net income (loss) is calculated on a quarterly basis based upon its 1.9% interest and incentive distributions to be distributed for the quarter (see Note 7), with a priority allocation of net income to the General Partners incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partners and limited partners ownership interests.
The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes that the partnership agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings are not allocated to the incentive distribution rights.
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnerships phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the awards vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income (loss) utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.
The following is a reconciliation of net income (loss) from continuing operations and net income from discontinued operations allocated to the general partner and common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding, including participating securities, plus the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnerships long-term incentive plan (see Note 14). The following table sets forth the reconciliation of the Partnerships weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as other comprehensive income (loss) or OCI and for the Partnership only include changes in the fair value of unsettled derivative contracts which were accounted for as cash flow hedges (see Note 10). The following table sets forth the calculation of the Partnerships comprehensive income (loss) (in thousands):
The Partnerships revenue primarily consists of the fees earned from its gathering and processing operations. Under certain agreements, the Partnership purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (NGLs), if any, off of delivery points on its systems. Under other agreements, the Partnership 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. In connection with the Partnerships gathering and processing operations, it enters into the following types of contractual relationships with its producers and shippers:
Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas. Revenue is a function of the volume of natural gas that the Partnership gathers and processes and is not directly dependent on the value of the natural gas. The Partnership is also paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas.
Percentage of Proceeds (POP) Contracts. These contracts provide for the Partnership to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, the Partnership and the producer are directly dependent on the volume of the commodity and its value; the Partnership effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP Contracts may include a fee component which is charged to the producer.
Keep-Whole Contracts. These contracts require the Partnership, as the processor and gatherer, to gather or purchase raw natural gas at current market rates. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of the Partnerships processing facility will be lower than the volume purchased at the wellhead primarily due to NGLs extracted when processed through a plant. The Partnership must make up or keep the producer whole for this loss in volume. To offset the make-up obligation, the Partnership retains the NGLs which are extracted and sells them for its own account. Therefore, the Partnership bears the economic risk (the processing margin risk) that (i) the volume of residue gas available for redelivery to the producer may be less than received from the producer; or (ii) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that the Partnership paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts the Partnership generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under Keep-Whole agreements is often lower in BTU content and thus, can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk.
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from the Partnerships records and management estimates of the related gathering and compression fees which are, in turn, based upon applicable product prices (see -Use of Estimates accounting policy for further description). The Partnership had unbilled revenues at June 30, 2010 and December 31, 2009 of $26.2 million and $65.4 million, respectively, which are included in accounts receivable within its consolidated balance sheets.
Recently Adopted Accounting Standards
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2010-06, Fair Value Measurements and Disclosures - Improving Disclosures about Fair Value Measurements, which provides enhanced disclosure requirements for activity in Levels 1, 2 and 3 fair value measurements. The update requires significant transfers in and out of Levels 1 and 2 fair value measurements to be reported separately and the reasons for such transfers to be disclosed. The update also requires information regarding purchases, sales, issuances, and settlements to be disclosed separately on a gross basis in the reconciliation of fair value measurements using unobservable inputs for all activity in Level 3 fair value measurements. Additionally, the update clarifies that fair value measurement for each class of assets and liabilities must be disclosed as well as disclosures pertaining to the inputs and valuation techniques for both recurring and nonrecurring fair value measurements in Levels 2 and 3. These requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those requirements will be effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Partnership adopted these requirements on January 1, 2010 and it did not have a material impact on its financial position, results of operations or related disclosures.
Recently Issued Accounting Standards
In July 2010, the FASB issued Accounting Standards Update 2010-20, Receivables Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (Update 2010-20). Update 2010-20 provides enhanced disclosure requirements for allowance for credit losses and the credit quality of financing receivables to assist financial statement users in assessing credit risk exposures and evaluating the adequacy of the allowance for credit losses. This amendment requires disclosures on a disaggregated basis that will further facilitate the evaluation of the nature of credit risk inherent in an entitys financing receivables, how
the risks are analyzed and assessed in arriving at the allowance for credit losses, and the changes and reasons for such changes in the allowance for credit losses. This amendment also requires disclosure of credit quality indicators, past due information, a roll-forward schedule of the allowance for credit losses, and any modifications to financing receivables. These requirements are effective for interim and annual reporting periods ending on or after December 15, 2010. The Partnership will apply these requirements upon its adoption on December 15, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.
NOTE 3 INVESTMENT IN JOINT VENTURE
On May 31, 2009, the Partnership and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates the Partnerships previously owned Appalachia natural gas gathering system, excluding the Partnerships northeastern Tennessee operations. Williams contributed cash and a note receivable of $25.5 million to the joint venture and owns 51% interest in Laurel Mountain. The Partnership contributed the Appalachia natural gas gathering system and owns a 49% interest in Laurel Mountain. The Partnership is required to make capital contributions to Laurel Mountain equal to 49% of any capital calls in order to maintain its current ownership interest in the joint venture. The Partnership is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams performs the day to day operations of the joint venture.
The Partnership recognizes its 49% ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheet. The Partnership accounts for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain as equity income on its consolidated statements of operations. As of June 30, 2010, the Partnership has utilized $8.5 million of the $25.5 million note receivable and paid cash of $5.6 million to make capital contributions to Laurel Mountain.
The following table provides the joint ventures summarized statement of operations for the three and six months ended June 30, 2010 and 2009 and balance sheet data as of June 30, 2010 and December 31, 2009 (in thousands):
NOTE 4 DISCONTINUED OPERATIONS
On May 4, 2009, the Partnership completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (Spectra). The Partnership accounted for the earnings of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $51.1 million on the sale of the NOARK assets within income from
discontinued operations on its consolidated statements of operations during the three and six months ended June 30, 2009. The following table summarizes the components included within income from discontinued operations on the Partnerships consolidated statements of operations (in thousands):
NOTE 5 COMMON UNIT EQUITY OFFERING
In August 2009, the Partnership sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. The Partnership also received a capital contribution from the General Partner of $0.4 million for the General Partner to maintain its 2.0% general partner interest in the Partnership. In addition, the Partnership issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units.
On January 7, 2010, the Partnership executed amendments to the warrants originally issued in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million to the Partnership. The Partnership utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 12) and to fund the early termination of certain derivative agreements (see Note 10).
The common units and warrants sold by the Partnership in the August 2009 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required the Partnership to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. The Partnership filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.
On March 31, 2010, the Partnership and the Operating Partnership amended their respective partnership agreements to temporarily waive the requirement that the General Partner make aggregate cash contributions of approximately $0.3 million, which was required in connection with the Partnerships issuance of 2,689,765 of its common units upon the exercise of certain warrants in January 2010. The waiver will remain in effect until the General Partner has received aggregate distributions from the Partnership sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to General Partners general partner interest in the Partnership is reduced to 1.9%. Both amendments were approved by the Partnerships conflicts committee and managing board, and are effective as of January 11, 2010.
NOTE 6 PREFERRED UNIT EQUITY OFFERINGS
On June 30, 2010, the Partnership sold 8,000 newly-created 12% Cumulative Class C Preferred Units of limited partner interest (the Class C Preferred Units) to Atlas Energy for cash consideration of $1,000 per Class C Preferred Unit (the Face Value). The Partnership plans to use the proceeds from the sale of the Class C Preferred Units for general partnership purposes. The Class C Preferred Units are entitled to receive
distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for the Partnerships common units. The Class C Preferred Units are not convertible into common units of the Partnership. The Partnership has the right at any time to redeem some or all of the outstanding Class C Preferred Units (but not less than 2,500 Class C Preferred Units) for cash at an amount equal to the Class C Preferred Face Value being redeemed plus accrued but unpaid dividends.
The sale of the Class C Preferred Units to Atlas Energy was exempt from the registration requirements of the Securities Act of 1933. The Class C Preferred Units are reflected on the Partnerships consolidated balance sheet as Class C preferred limited partners interest within Partners Capital.
NOTE 7 CASH DISTRIBUTIONS
The Partnership is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the General Partner. If common unit distributions in any quarter exceed specified target levels, the General Partner will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by the Partnership for the period from January 1, 2009 through June 30, 2010 were as follows:
In accordance with the restrictions in the Partnerships senior secured credit facility, the Partnership did not declare cash distributions for the quarters ended June 30, 2009 through June 30, 2010 (see Note 12).
NOTE 8 PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment (dollars in thousands):
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the assets estimated useful life. The Partnership follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnerships results of operations.
During the six months ended June 30, 2010, the Partnership entered into capital lease arrangements having obligations of $2.8 million at inception. Leased property and equipment meeting capital lease criteria are capitalized at the original cost of the equipment and are included within property plant and equipment on the Partnerships consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnerships consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets. The Partnership did not enter into any capital lease arrangements during the six months ended June 30, 2009, and had no capital lease obligations as of December 31, 2009.
NOTE 9 OTHER ASSETS
The following is a summary of other assets (in thousands):
Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12). During May 2009, the Partnership recorded $2.3 million of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see Note 4). Total amortization expense of deferred finance costs was $1.6 million and $3.7 million for the three months ended June 30, 2010 and 2009, respectively and $3.2 million and $4.7 million for the six months ended June 30, 2010 and 2009, respectively, which is recorded within interest expense on the Partnerships consolidated statements of operations. Amortization expense related to deferred finance costs is estimated to be as follows for each of the next five calendar years: 2010 to 2012 - $6.2 million per year; 2013 - $4.4 million; 2014 - $1.7 million.
NOTE 10 DERIVATIVE INSTRUMENTS
The Partnership uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. The Partnership enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. It also previously entered into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold or interest payments on the underlying debt instrument are due. Under its swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.
On July 1, 2008, the Partnership discontinued hedge accounting for certain existing qualified crude oil derivatives, utilized to hedge forecasted NGL production, due to significant ineffectiveness. The Partnership also discontinued hedge accounting for all of its other qualified commodity derivatives for consistency in reporting of all commodity-based derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in its consolidated statements of operations. The fair
value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within Partners capital on the Partnerships consolidated balance sheet, will be reclassified to the Partnerships consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.
Derivatives are recorded on the Partnerships consolidated balance sheet as assets or liabilities at fair value. Premium costs for purchased options are recorded on the Partnerships consolidated balance sheet as the initial value of the options. Changes in the fair value of the options are recognized within other income (loss), net as unrealized gain (loss) on the Partnerships consolidated statements of operations. Premium costs are reclassified to realized gain (loss) within other income (loss), net at the time the option expires or is exercised. At June 30, 2010 the Partnership reflected net derivative assets on its consolidated balance sheets of $3.6 million and at December 31, 2009, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $43.3 million. Of the $27.8 million of net loss in accumulated other comprehensive loss within Partners Capital on the Partnerships consolidated balance sheet at June 30, 2010, the Partnership will reclassify $13.0 million of losses to natural gas and liquids revenue on the Partnerships consolidated statements of operations over the next twelve month period. Aggregate losses of $14.8 million will be reclassified to natural gas and liquids revenue on the Partnerships consolidated statements of operations in later periods. At June 30, 2010, no derivative instruments are designated as hedges for hedge accounting purposes.
The fair value of the Partnerships derivative instruments was included in its consolidated balance sheets as follows (in thousands):
The following table summarizes the Partnerships gross fair values of derivative instruments for the period indicated (in thousands):
As of June 30, 2010, the Partnership had no interest rate derivative contracts. The following table summarizes the Partnerships commodity derivatives, which are not designated for hedge accounting (dollars and volumes in thousands):
Fixed Price Swaps
During the six months ended June 30, 2010 and 2009, the Partnership made net payments of $25.3 million and $5.0 million, respectively, related to the early termination of derivative contracts. The terminated derivative contracts were to expire at various times through the fourth quarter of 2010.
The following tables summarize the gross effect of all derivative instruments, including the transactions referenced above, on the Partnerships consolidated statements of operations for the periods indicated (in thousands):
NOTE 11 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnerships own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:
Level 1 Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 Unobservable inputs that reflect the entitys own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 10). At June 30, 2010, all of the Partnerships derivative contracts are defined as
Level 2, with the exception of the Partnerships NGL fixed price swaps and NGL options. The Partnerships Level 2 commodity derivatives include natural gas and crude oil swaps and options which are calculated based upon observable market data related to the change in price of the underlying commodity. These swaps and options are calculated by utilizing the New York Mercantile Exchange (NYMEX) quoted price for futures and option contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula. Valuations for the Partnerships NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar locations, and therefore are defined as Level 3. Valuations for the Partnerships NGL options are based on forward price curves developed by the related financial institutions, and therefore are defined as Level 3.
The following table represents the Partnerships assets and liabilities recorded at fair value as of June 30, 2010 (in thousands):
The Partnerships Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of the Partnerships Level 3 derivative instruments for the six months ended June 30, 2010 (in thousands):
Other Financial Instruments
The estimated fair value of the Partnerships other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.
The Partnerships current assets and liabilities on its consolidated balance sheets, other than the derivatives discussed above, are considered to be financial instruments for which the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnerships total debt at June 30, 2010 and December 31, 2009, which consists principally of the term loan, the Senior Notes and borrowings under the credit facility, was $1,170.2 million and $1,194.2 million, respectively, compared with the carrying amounts of $1,208.4 million and $1,254.2 million, respectively. The
term loan and Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under the credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.
NOTE 12 DEBT
Total debt consists of the following (in thousands):
Cash payments for interest related to debt were $54.4 million and $40.6 million for the six months ended June 30, 2010 and 2009, respectively.
Term Loan and Revolving Credit Facility
At June 30, 2010, the Partnership had a senior secured credit facility with a syndicate of banks which consisted of a $425.8 million term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under the credit facility bear interest, at the Partnerships option, at either (i) adjusted LIBOR, subject to a floor of 2.0% per annum, plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on both the outstanding revolving credit facility and term loan borrowings at June 30, 2010 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $8.1 million was outstanding at June 30, 2010. These outstanding letter of credit amounts were not reflected as borrowings on the Partnerships consolidated balance sheet. At June 30, 2010, the Partnership had $86.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.
The Partnerships senior secured credit facility restricts it from paying cash distributions unless its senior secured leverage ratio meets certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million. The senior secured leverage ratio requirement was not met for the quarter ending June 30, 2010. Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnerships property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and Laurel Mountain; and by the guaranty of each of the Partnerships consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on the Partnerships ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. The Partnership is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute working capital borrowings pursuant to its partnership agreement. The Partnership is in compliance with these covenants as of June 30, 2010 and expects to be in compliance in future periods.
The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against the Partnership in excess of a specified amount, and a change of control of the Partnerships General Partner. The credit facility requires the Partnership to maintain the following ratios:
As of June 30, 2010, the Partnerships leverage ratio was 7.26 to 1.0, its senior secured leverage ratio was 4.30 to 1.0, and its interest coverage ratio was 1.66 to 1.0.
At June 30, 2010, the Partnership had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (8.75% Senior Notes) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (8.125% Senior Notes; collectively, the Senior Notes). The Partnerships 8.125% Senior Notes are presented combined with a net $3.6 million of unamortized discount as of June 30, 2010. Interest on the Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the 8.125% Senior Notes are redeemable at any time after December 31, 2010, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, the Partnership may redeem up to 35% of the aggregate principal amount of the 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by the Partnership at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnerships secured debt, including the Partnerships obligations under its credit facility.
Indentures governing the Senior Notes in the aggregate contain covenants, including limitations of the Partnerships ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Partnership is in compliance with these covenants as of June 30, 2010.
NOTE 13 COMMITMENTS AND CONTINGENCIES
The Partnership is a party to various routine legal proceedings arising in the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.
On February 26, 2010, the Partnership received notice from Williams, its partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by the Partnership to Laurel Mountain. Under the Formation and Exchange Agreement with Williams: (i) Williams had nine months after closing (the Claim Date) to assert any alleged title defects, and (ii) the Partnership has 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects. On March 26, 2010, the Partnership delivered notice, disputing Williams alleged title defects as well as the amounts claimed. The Partnership is continuing its review with respect to the title defects that have been alleged. At the end of the cure period with respect to any remaining title defects, the Partnership may elect,
at its option, to pay Williams for the cost of such defects, up to a total of $3.5 million, or indemnify Williams with respect to such title defects. Although an adverse outcome is reasonably possible, it is not currently possible to evaluate the amount that the Partnership may be required to pay with respect to such alleged title defects.
NOTE 14 BENEFIT PLANS
Generally, all share-based payments to employees, which are not cash settled, including grants of employee stock options and phantom units, are recognized in the financial statements based on their fair values on the date of the grant.
A phantom unit entitles a grantee to receive a common limited partner unit upon vesting of the phantom unit. In tandem with phantom unit grants, participants may be granted a distribution equivalent right (DER), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. Except for phantom units awarded to non-employee managing board members of the General Partner, a committee (the Committee) appointed by the General Partners managing board determines the vesting period for phantom units.
A unit option entitles a grantee to purchase a common limited partner unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the common unit on the date of grant of the option. The Committee shall determine how the exercise price may be paid by the grantee. The Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant.
Partnerships Long-Term Incentive Plans
The Partnership has a 2004 Long-Term Incentive Plan (2004 LTIP) and a 2010 Long-Term Incentive Plan (2010 LTIP and collectively with the 2004 LTIP, the LTIPs), in which officers, employees, non-employee managing board members of the General Partner, employees of the General Partners affiliates, and consultants are eligible to participate. The LTIPs are administered by the Committee. On June 15, 2010, the Partnerships unitholders approved the terms of the 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and distribution equivalent rights (DERs). Under the 2010 LTIP, the Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in the 2004 LTIP. At June 30, 2010, the Partnership had 703,774 phantom units and unit options outstanding under the Partnerships LTIPs, with 2,504,459 phantom units and unit options available for grant.
Through June 30, 2010, phantom units granted under the LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (Bonus Units), under the Partnerships subsidiarys plan discussed below, agreed to exchange their Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period, with the first tranche vesting on June 1, 2010. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the LTIP. At June 30, 2010, there were 193,685 units outstanding under the LTIPs that will vest within the following twelve months. All phantom units outstanding under the LTIPs at June 30, 2010 include DERs granted to the participants by the Committee. The amounts paid with respect to LTIP DERs were $11,000 and $0.1 million for the three months and six months ended June 30, 2009, respectively. These amounts were recorded as a reduction of Partners capital on the Partnerships consolidated balance sheet. No DERs were paid for the six months ended June 30, 2010.
The following table sets forth the Partnerships phantom unit activity for the periods indicated:
At June 30, 2010, the Partnership had approximately $3.6 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIPs based upon the fair value of the awards.
Through June 30, 2010, unit options granted under the Partnerships LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnerships LTIPs. There are 25,000 unit options outstanding under the Partnerships LTIPs at June 30, 2010 that will vest within the following twelve months.
The following table sets forth the Partnerships unit option activity for the periods indicated:
At June 30, 2010, the Partnership had approximately $5,000 of unrecognized compensation expense related to unvested unit options outstanding under the Partnerships LTIPs based upon the fair value of the awards.
The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:
Employee Incentive Compensation Plan and Agreement
A wholly-owned subsidiary of the Partnership has an incentive plan (the Cash Plan) which allows for equity-indexed cash incentive awards to employees of the Partnership (the Participants), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a Named Executive Officer of the Partnership (as such term is defined under the rules of the Securities and Exchange Commission). The Cash Plan is administered by a committee appointed by the chief executive officer of the Partnership. Under the Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee, which granted 325,000 bonus units during 2009. In addition, the subsidiary granted an award of 50,000 bonus units to an executive officer on substantially the same terms as the bonus units available under the Cash Plan (the bonus units issued under the Cash Plan and under the separate agreement are, for purposes hereof, referred to as Bonus Units). A Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the Bonus Unit. Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 Bonus Units outstanding at June 16, 2010 agreed to exchange their Bonus Units for phantom units, effective as of June 1, 2010.
A total of 25,000 of the remaining 75,000 Bonus Units vested on June 1, 2010 and an additional 25,000 Bonus Units will vest within the following twelve months. The Partnership recognized compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. The Partnership recognized a credit of $0.3 million and $1.0 million of compensation expense within general and administrative expense on its consolidated statements of operations in the three and six months ended June 30, 2010, respectively, related to the re-measurement of the outstanding Bonus Units during these periods. The Partnership had $0.5 million and $1.2 million, at June 30, 2010 and December 31, 2009, respectively, included within accrued liabilities on its consolidated balance sheet with regard to these awards, which represents their fair value as of those dates.
NOTE 15 RELATED PARTY TRANSACTIONS
The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by the General Partner and employees of Atlas Energy. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses the General Partner and its affiliates for compensation and benefits related to its employees who perform services for the Partnership based upon an estimate of the time spent by such persons on activities for the Partnership. Other indirect costs, such as rent for offices, are allocated to the Partnership by Atlas Energy based on the number of its employees who devote their time to activities on the Partnerships behalf.
The partnership agreement provides that the General Partner will determine the costs and expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. The Partnership reimbursed the General Partner and its affiliates $0.4 million for both the three months ended June 30, 2010 and 2009, and $0.8 million for both the six months ended June 30, 2010 and 2009, for compensation and benefits related to its employees. There were no reimbursements for direct expenses incurred by the General Partner and its affiliates for the six months ended June 30, 2010 and 2009. The General Partner believes that the method utilized in allocating costs to the Partnership is reasonable.
NOTE 16 SEGMENT INFORMATION
The Partnership has two reportable segments which reflect the way the Partnership manages its operations.
The Mid-Continent segment consists of the Chaney Dell, Elk City/Sweetwater, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and gathering of natural gas.
The Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin area of the northeastern United States and services drilling activity in the Marcellus Shale area in southwestern Pennsylvania. Effective May 31, 2009, the Appalachia operations were principally conducted through its Tennessee operations and the Partnerships 49% ownership interest in Laurel Mountain, a joint venture to which the Partnership contributed its natural gas transportation, gathering and processing assets located in northeastern Appalachia. The Partnership recognizes its ownership interest in Laurel Mountain under the equity method of accounting. Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates.
The following summarizes the Partnerships reportable segment data for the periods indicated (in thousands):
The following table summarizes the Partnerships natural gas and liquids revenues by product or service for the periods indicated (in thousands):
NOTE 17 SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Partnerships term loan and revolving credit facility is guaranteed by its wholly-owned subsidiaries. The guarantees are full, unconditional, joint and several. The Partnerships consolidated financial statements as of June 30, 2010 and December 31, 2009 and for the three and six months ended June 30, 2010 and 2009 include the financial statements of Atlas Pipeline Mid-Continent WestOk, LLC (Chaney Dell LLC) and Atlas Pipeline Mid-Continent WestTex, LLC (Midkiff/Benedum LLC), entities in which the Partnership has 95% interests. Under the terms of the term loan and revolving credit facility, Chaney Dell LLC and Midkiff/Benedum LLC are non-guarantor subsidiaries as they are not wholly-owned by the Partnership. The following supplemental condensed consolidating financial information reflects the Partnerships stand-alone accounts, the combined accounts of the guarantor subsidiaries, the combined accounts of the non-guarantor subsidiaries, the consolidating adjustments and eliminations and the Partnerships consolidated accounts as of June 30, 2010 and December 31, 2009 and for the three and six months ended June 30, 2010 and 2009. For the purpose of the following financial information, the Partnerships investments in its subsidiaries and the guarantor subsidiaries investments in their subsidiaries are presented in accordance with the equity method of accounting (in thousands):