EXHIBIT 99.1
DCP Midstream GP, LP
(A Delaware Limited Partnership)
Unaudited Condensed Consolidated Balance Sheet
As of June 30, 2007
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET OF
DCP MIDSTREAM GP, LP
TABLE OF CONTENTS
Page | ||
Unaudited Condensed Consolidated Balance Sheet as of June 30, 2007 | 2 | |
Notes to Unaudited Condensed Consolidated Balance Sheet | 3 |
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DCP MIDSTREAM GP, LP
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET
AS OF JUNE 30, 2007
($ in millions)
ASSETS | ||||
Current assets: | ||||
Cash and cash equivalents | $ | 55.0 | ||
Accounts receivable: | ||||
Trade, net of allowance for doubtful accounts of $0.6 million | 40.2 | |||
Affiliates | 30.4 | |||
Inventories | 30.3 | |||
Unrealized gains on non-trading derivative and hedging instruments | 3.2 | |||
Other | 0.2 | |||
Total current assets | 159.3 | |||
Property, plant and equipment, net | 370.7 | |||
Goodwill | 29.3 | |||
Intangible assets, net | 15.0 | |||
Equity method investments | 6.4 | |||
Unrealized gains on non-trading derivative and hedging instruments | 5.0 | |||
Other long-term assets | 1.3 | |||
Total assets | $ | 587.0 | ||
LIABILITIES AND MEMBER’S DEFICIT | ||||
Current liabilities: | ||||
Accounts payable: | ||||
Trade | $ | 70.7 | ||
Affiliates | 21.6 | |||
Unrealized losses on non-trading derivative and hedging instruments | 4.4 | |||
Accrued interest payable | 0.4 | |||
Other | 7.3 | |||
Total current liabilities | 104.4 | |||
Long-term debt | 249.0 | |||
Unrealized losses on non-trading derivative and hedging instruments | 10.3 | |||
Other long-term liabilities | 4.3 | |||
Non-controlling interest | 224.0 | |||
Commitments and contingent liabilities | ||||
Member’s deficit: | ||||
Member’s deficit | 178.0 | |||
Note receivable from DCP Midstream, LLC | (183.0 | ) | ||
Total member’s deficit | (5.0 | ) | ||
Total liabilities and member’s deficit | $ | 587.0 | ||
See accompanying notes to unaudited condensed consolidated balance sheet.
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DCP MIDSTREAM GP, LP
NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET
AS OF JUNE 30, 2007
1. Description of Business and Basis of Presentation
DCP Midstream GP, LP, with its consolidated subsidiaries, or us, we or our, is a Delaware limited partnership, whose membership interests are owned by DCP Midstream, LLC and DCP Midstream GP, LLC. We own a 1.7% interest in and act as the general partner for DCP Midstream Partners, LP, or DCP Partners or the partnership, a master limited partnership formed in August 2005, which is engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and the business of producing, transporting and selling propane and natural gas liquids, or NGLs. DCP Partners’ operations and activities are managed by us. We, in turn, are managed by our general partner, DCP Midstream GP, LLC, which we refer to as our General Partner, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC directs DCP Partners’ business operations through their ownership and control of our General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to DCP Partners and operate our assets. DCP Midstream, LLC is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips.
The partnership includes: our Northern Louisiana system assets; our Southern Oklahoma system (which was acquired in May 2007); our NGL transportation pipelines; and our wholesale propane logistics business.
The unaudited condensed consolidated balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The unaudited condensed consolidated balance sheet includes the accounts of DCP Midstream GP, LP and DCP Partners. We consolidate DCP Partners as we act as the general partner and exercise control, and as the limited partners do not have substantive kick-out or participating rights. DCP Partners’ investments in greater than 20% owned affiliates, which are not variable interest rights and where DCP Partners does not exercise control, are accounted for using the equity method. All significant intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations and other affiliates have been identified in the unaudited condensed consolidated balance sheet as transactions between affiliates (see Note 5).
The unaudited condensed consolidated balance sheet reflects all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the results of operations for the interim period. Certain information and notes normally included have been condensed or omitted from this interim balance sheet. The unaudited condensed consolidated balance sheet should be read in conjunction with the consolidated balance sheet and notes thereto as of December 31, 2006 included in DCP Partners’ Current Report on Form 8-K filed with the Securities and Exchange Commission, or SEC, on April 20, 2007.
2. Summary of Significant Accounting Policies
Use of Estimates — Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the unaudited condensed consolidated balance sheet and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.
Accounting for Risk Management and Hedging Activities and Financial Instruments — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We will use the mark-to-market method of accounting for all commodity cash flow hedges beginning in July 2007. As a result, the remaining loss of less than $0.1 million deferred in accumulated other comprehensive income as of June 30, 2007 will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings.
Accounting for Sales of Units by a Subsidiary — We account for sales of units by a subsidiary by recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. As a result, we have deferred approximately $2.0 million of gain on sale of common units of DCP Partners, which is included in other long-term liabilities in the condensed consolidated balance sheet. This gain is related to DCP Partners’ private placement in June 2007. We will recognize this gain in earnings upon conversion of all of DCP Partners’ subordinated units to common units.
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3. Recent Accounting Pronouncements
Statement of Financial Accounting Standards, or SFAS, No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115, or SFAS 159 — In February 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated financial position.
SFAS No. 157, Fair Value Measurements, or SFAS 157 — In September 2006, the FASB issued SFAS 157, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated financial position.
FASB Interpretation Number, or FIN, 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109, or FIN 48—In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109,Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 were effective for us on January 1, 2007, and the adoption of FIN 48 did not have a material impact on our consolidated financial position.
4. Acquisitions
Gathering and Compression Assets
On July 1, 2007, we acquired a 25% limited liability company interest in DCP East Texas Holdings, LLC, a 40% limited liability company interest in Discovery Producer Services LLC and a derivative instrument from DCP Midstream, LLC for aggregate consideration of approximately $271.3 million, consisting of approximately $243.7 million in cash, including $1.3 million for net working capital and other adjustments, the issuance of 620,404 common units valued at $27.0 million and the issuance of 12,661 general partner equivalent units valued at $0.6 million. We financed the cash portion of this transaction with borrowings of $245.9 million under our amended credit facility. Transfers of assets between DCP Midstream, LLC and us represent transfers of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. The $118.0 million excess purchase price over the historical basis of the net acquired assets will be recorded as a reduction to non-controlling interest, and the $27.6 million of common and general partner equivalent units issued as partial consideration for this transaction will be recorded as an increase to non-controlling interest, for financial accounting purposes.
In May 2007, we agreed to acquire certain subsidiaries of Momentum Energy Group Inc., or MEG, from DCP Midstream, LLC for $165.0 million, subject to closing adjustments. This transaction closed in the third quarter of 2007. The purchase price consisted of approximately $153.8 million of cash and the issuance of 275,735 common units to an affiliate of DCP Midstream, LLC that were valued at approximately $12.0 million. We have incurred post-closing purchase price adjustments to date that include a liability of $9.0 million for net working capital and general and administrative charges. We financed this transaction with $120.0 million of borrowings under our amended credit facility, the issuance of common units and cash on hand. On May 21, 2007, in connection with this acquisition, DCP Partners entered into a common unit purchase agreement with certain institutional investors to sell 2,380,952 common limited partner units in a private placement at $42.00 per unit, or approximately $100.0 million in the aggregate. In connection with this common unit purchase agreement, DCP Partners has a registration rights agreement to file a shelf registration statement with the SEC to register the units within 90 days of the close of the private placement. In, addition the registration rights agreement requires DCP Partners to use its commercially reasonable efforts to cause the registration statement to become effective within 180 days of the closing of the private placement. If the registration statement covering the common units is not declared effective by the SEC within 180 days of the closing of the private placement, then DCP Partners will be liable to the purchasers for liquidated damages of 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for the first 60 days following the 180th day, increasing by an additional 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period.
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In May 2007, we acquired certain gathering and compression assets located in Southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181.1 million.
In April 2007, we acquired certain gathering and compression assets located in Northern Louisiana from Laser Gathering Company, LP for approximately $10.2 million, subject to customary purchase price adjustments.
Wholesale Propane Logistics Business
On November 1, 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC for aggregate consideration consisting of approximately $82.9 million, which consisted of $77.3 million in cash ($9.9 million of which was paid in January 2007), and the issuance of 200,312 Class C units valued at approximately $5.6 million. Included in the aggregate consideration was $10.5 million of costs incurred through October 31, 2006, which were associated with the construction of a new pipeline terminal. The transfer of assets between DCP Midstream, LLC and us represents a transfer of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. The $26.3 million excess purchase price over historical basis of net acquired assets was recorded as a reduction to non-controlling interest, and the $5.6 million of Class C units issued as partial consideration for this transaction were recorded as an increase to non-controlling interest, for financial accounting purposes.
5. Agreements and Transactions with Affiliates
DCP Midstream, LLC
DCP Midstream, LLC provided centralized corporate functions on behalf of our predecessor operations, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The predecessor’s share of those costs was allocated based on the predecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investments, and intangible assets, net) as compared to DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used were reasonable and resulted in an allocation to the predecessors of their respective costs of doing business, which were borne by DCP Midstream, LLC.
Omnibus Agreement
We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Omnibus Agreement: (1) states that the annual fee of $4.8 million for the initial assets under the agreement was fixed at such amount for 2006, subject to annual increases in the Consumer Price Index, which increased to $5.0 million for 2007; (2) effective November 2006, includes an additional annual fee of $2.0 million related to the acquisition of our wholesale propane logistics business from DCP Midstream, LLC, subject to the same conditions noted above; (3) effective May 2007, includes an additional annual fee of $0.2 million related to the Southern Oklahoma asset acquisition, subject to the same conditions noted above; (4) effective with our acquisition of Discovery includes an additional annual fee of $0.2 million; (5) effective August 2007, includes an additional annual fee of $0.6 million for general and administrative expenses payable to DCP Midstream, LLC to account for additional services provided to us; and (6) effective with our acquisition of the MEG subsidiaries includes an additional annual fee of $1.6 million.
The Omnibus Agreement addresses the following matters:
• | our obligation to reimburse DCP Midstream, LLC for the payment of operating expenses, including salary and benefits of operating personnel, it incurs on our behalf in connection with our business and operations; |
• | our obligation to reimburse DCP Midstream, LLC for providing us with general and administrative services with respect to our business and operations, which is $7.2 million in 2007, subject to an increase for 2008 based on increases in the Consumer Price Index and subject to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of the special committee of the General Partner’s board of directors; |
• | our obligation to reimburse DCP Midstream, LLC for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage; |
• | DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; |
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• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements were in effect as of the closing of our initial public offering in December 2005, until the earlier to occur of the fifth anniversary of the closing of our initial public offering or such time as we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts. |
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions, will be terminable by DCP Midstream, LLC at its option if we are removed without cause and units held by us and our affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of us as the general partner (DCP Midstream GP, LP), or the General Partner (DCP Midstream GP, LLC).
Indemnification
Under the Omnibus Agreement, DCP Midstream, LLC will indemnify us for three years after the closing of our initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of our initial public offering. DCP Midstream, LLC’s maximum liability for this indemnification obligation does not exceed $15.0 million and DCP Midstream, LLC does not have any obligation under this indemnification until our aggregate losses exceed $250,000. DCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of our initial public offering. We have agreed to indemnify DCP Midstream, LLC against environmental liabilities related to our assets to the extent DCP Midstream, LLC is not required to indemnify us.
Additionally, DCP Midstream, LLC will indemnify us for losses attributable to title defects, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify DCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to DCP Midstream, LLC’s indemnification obligations. In addition, DCP Midstream, LLC has agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions required to be made by us to Black Lake Pipe Line Company, or Black Lake, associated with any repairs to the Black Lake pipeline that are determined to be necessary as a result of the currently ongoing pipeline integrity testing occurring from 2005 through 2007. DCP Midstream, LLC had also agreed to indemnify us for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that were determined to be necessary as a result of pipeline integrity testing that occurred in 2006. Pipeline integrity testing and repairs were our responsibility and were recognized as operating and maintenance expense. Reimbursement of these expenses from DCP Midstream, LLC were not significant and were recognized by us as capital contributions.
In connection with our acquisitions of East Texas and Discovery from DCP Midstream, LLC, an affiliate of DCP Midstream, LLC will indemnify us for one year following the closing for the breach of the representations and warranties made under the acquisition agreement and certain environmental matters and tax matters associated with these assets that were identified at the time of closing and that were attributable to periods prior to the closing date. In addition, the same affiliate of DCP Midstream, LLC agreed to indemnify us for one year after closing for the underpayment of trade payables that pertain to periods prior to closing and agreed to indemnify us for two years after closing for any claims for fines or penalties of any governmental authority for periods prior to the closing and that are associated with certain East Texas assets that were formerly owned by Gulf South and UP Fuels. The indemnity obligation for breach of certain representations and warranties is not effective until claims exceed in the aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
Other Agreements and Transactions with DCP Midstream, LLC
DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to the inlet of the Pelico system, and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Because of DCP Midstream, LLC’s ability to move natural gas around Pelico, there are certain contractual relationships around Pelico that define how natural gas is bought and sold between us and DCP Midstream, LLC. The agreement is described below:
• | DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. |
• | If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index-based price, less a contractually agreed-to marketing fee. |
• | In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC, plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential, plus a fixed fuel charge and other related adjustments. |
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In addition, we sell NGLs and condensate from our Minden and Ada processing plants, and condensate from our Pelico system to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for transportation and other charges from the tailgate of the respective asset. We also sell propane to a subsidiary of DCP Midstream, LLC.
We also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze pipeline, pursuant to a fee-based rate that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on the Seabreeze pipeline under a 17-year transportation agreement expiring in 2022.
In December 2006, we completed construction of our Wilbreeze pipeline, which connects a DCP Midstream, LLC gas processing plant to our Seabreeze pipeline. The project is supported by a 10-year NGL product dedication agreement with DCP Midstream, LLC.
We anticipate continuing to purchase commodities from and sell commodities to DCP Midstream, LLC in the ordinary course of business.
We have a note receivable from DCP Midstream, LLC totaling $183.0 million. This note is due on demand; however, we do not anticipate requiring DCP Midstream, LLC to repay this amount. Accordingly we have reflected this receivable as a component of member’s deficit. The note receivable bears interest at the greater of 5.00% or the applicable federal rate in effect under section 1274(d) of the Internal Revenue Code of 1986. The interest rate in effect on the note was 5.00% at June 30, 2007. All interest income earned under the note has been distributed to DCP Midstream, LLC.
In accordance with our partnership agreement, we distribute all available cash to our members according to their membership interests.
ConocoPhillips
We have multiple agreements whereby we provide a variety of services to ConocoPhillips and its affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $1.5 million of capital reimbursements during the six months ended June 30, 2007.
We had accounts receivable and accounts payable with affiliates as follows as of June 30, 2007 ($ in millions):
DCP Midstream, LLC: | |||
Accounts receivable | $ | 19.9 | |
Accounts payable | $ | 19.5 | |
Spectra Energy: | |||
Accounts receivable | $ | 0.3 | |
ConocoPhillips: | |||
Accounts receivable | $ | 10.2 | |
Accounts payable | $ | 2.1 |
6. Intangible Assets
Intangible assets consist primarily of commodity purchase contracts. The gross carrying amount and accumulated amortization for the commodity purchase contracts and other intangible assets are included in the accompanying unaudited condensed consolidated balance sheet as intangible assets, net, and were as follows as of June 30, 2007 ($ in millions):
Gross carrying amount | $ | 16.9 | ||
Accumulated amortization | (1.9 | ) | ||
Intangible assets, net | $ | 15.0 | ||
Intangible assets increased in May 2007 as a result of the Southern Oklahoma asset acquisition, through which $12.5 million of net commodity purchase contracts were acquired. These intangible assets have a life of 15 years and are being amortized through 2022.
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As of June 30, 2007, the remaining amortization periods for these contracts range from approximately two to 20 years, with a weighted-average remaining period of approximately 15 years.
7. Debt
Long-term debt at June 30, 2007 consisted of a $249.0 million balance on our revolving credit facility, due June 21, 2012, with a weighed-average interest rate of 5.77%.
Credit Agreements
On June 21, 2007, we entered into the Amended and Restated Credit Agreement, or the Amended Credit Agreement, that replaced our existing credit agreement, or the Credit Agreement, which consists of:
• | a $600.0 million revolving credit facility; and |
• | a $250.0 million term loan facility. |
At June 30, 2007, we had $0.2 million of letters of credit outstanding. In June 2007, we incurred $0.5 million of debt issuance costs associated with the Amended Credit Agreement. These expenses are deferred as other long-term assets in the unaudited condensed consolidated balance sheet and will be amortized over the term of the Amended Credit Agreement.
Under the Amended Credit Agreement, indebtedness under the revolving credit facility bears interest at either: (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50%; or (2) LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our leverage level or credit rating. As of June 30, 2007, the weighted-average interest rate on our revolving credit facility was 5.77% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to either: (1) LIBOR plus 0.10%; or (2) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50%.
The Amended Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended Credit Agreement) of not more than 5.75 to 1.0 through and including the quarter ended June 30, 2007 and 5.0 to 1.0 thereafter, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.50 to 1.0. The Amended Credit Agreement also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as is defined by the Amended Credit Agreement) of equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination.
Bridge Loan
In May 2007, we entered into a two-month bridge loan, or the Bridge Loan, which provided for borrowings up to $100.0 million, and had terms and conditions substantially similar to those of our Credit Agreement. In conjunction with our entering into the Bridge Loan, our Credit Agreement was amended to provide for additional unsecured indebtedness, of an amount not to exceed $100.0 million, which was due and payable no later than August 9, 2007.
We used borrowings on the Bridge Loan of $88.0 million to partially fund the Southern Oklahoma asset acquisition. The remaining $12.0 million available for borrowing on the Bridge Loan was not utilized. We used a portion of the net proceeds of a private placement of limited partner units to extinguish the $88.0 million outstanding on the Bridge Loan.
8. Non-Controlling Interest
Non-controlling interest represents the ownership interests of DCP Partners’ public unitholders in net assets of DCP Partners through DCP Partners’ publicly traded common units, as well as affiliate ownership interests in common units and in all of the class C, subordinated and treasury units. We own a 1.7% general partner interest in DCP Partners. For financial reporting purposes, the assets and liabilities of DCP Partners are consolidated with those of our own, with any third party and affiliate investors’ interest in our unaudited condensed consolidated balance sheet amounts shown as non-controlling interest. Distributions to and contributions from non-controlling interests represent cash payments and cash contributions, respectively, from such third-party and affiliate investors.
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At June 30, 2007, DCP Partners had outstanding 13,362,923 common units, 200,312 class C units and 7,142,857 subordinated units, offset by 4,000 treasury units.
General— DCP Partners’ partnership agreement requires that, within 45 days after the end of each quarter, DCP Partners distribute all Available Cash (defined below) to unitholders of record on the applicable record date, as determined by us as the general partner.
In April 2007, DCP Partners filed with the SEC a universal shelf registration statement on Form S-3 with a maximum aggregate offering price of $1.5 billion, which will, upon effectiveness, allow DCP Partners to register and issue additional partnership units and debt obligations.
On June 22, 2007, DCP Partners entered into a private placement agreement, or the Private Placement Agreement, with a group of institutional investors for $130.0 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $128.5 million, net of offering costs. In connection with the Private Placement Agreement, DCP Partners entered into a registration rights agreement with institutional investors that requires DCP Partners to file a shelf registration statement with the SEC to register the units by the earlier of within 120 days of the close of the private placement or when a shelf registration statement is filed to register the units issued and sold by DCP Partners under a common unit purchase agreement, in connection with the closing of the MEG acquisition. In addition the registration rights agreement requires DCP Partners to use their commercially reasonable efforts to cause the registration statement to become effective within 210 days of the closing of the private placement, or they will be liable to the institutional investors for liquidated damages of 0.25% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period for the first 60 days following the 210th day, increasing by an additional 0.25% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price times the number of registrable securities held by the institutional investors per 30-day period.
As a result of the Private Placement Agreement, we recognized a deferred gain of $2.0 million in other long-term liabilities related to the gain on sale of common units in DCP Partners. We will recognize this gain in earnings upon conversion of all of DCP Partners’ subordinated units to common units.
Definition of Available Cash— Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
• | less the amount of cash reserves established by the general partner to: |
• | provide for the proper conduct of our business; |
• | comply with applicable law, any of our debt instruments or other agreements; or |
• | provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters; |
• | plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter. |
General Partner Interest and Incentive Distribution Rights — Prior to June 22, 2007, we, as the general partner, were entitled to 2% of all quarterly distributions that DCP Partners makes prior to their liquidation. We have the right, but not the obligation, to contribute a proportionate amount of capital to DCP Partners to maintain our general partner interest. Our interest in these distributions was reduced to 1.7% on June 22, 2007 as a result of the issuance of the 3,005,780 common limited partner units in conjunction with the Private Placement Agreement.
The incentive distribution rights held by us entitle us to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Our incentive distribution rights were not reduced as a result of the Private Placement Agreement, and will not be reduced if DCP Partners issues additional units in the future and we do not contribute a proportionate amount of capital to maintain our general partner interest. Please read theDistributions of Available Cash during the Subordination PeriodandDistributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on our incentive distribution rights.
Class C Units— The Class C units have the same liquidation preference, rights to cash distributions and voting rights as the common units. On July 2, 2007, the Class C units were converted to common units.
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Subordinated Units—All of the subordinated units are held by DCP Midstream, LLC. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The subordination period has an early termination provision that permits 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2008 and the other 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2009, provided the tests for ending the subordination period contained in the partnership agreement are satisfied. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.
Treasury Units (unaudited)—In March 2007, we purchased 4,000 units on the open market, at an average cost of $39.16 per unit. These units were held as treasury units at June 30, 2007, and will be used for director compensation pursuant to the DCP Midstream Partners, LP Long-Term Incentive Plan, or LTIP. In August 2007, these units were issued to our general partner.
Distributions of Available Cash during the Subordination Period— DCP Partners’ partnership agreement, after adjustment for our relative ownership level, currently 1.7%, requires that DCP Partners make distributions of Available Cash for any quarter during the subordination period in the following manner:
• | first,to the common unitholders and us as the general partner, in accordance with the pro rata interests, until DCP Partners distributes for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter; |
• | second,to the common unitholders and us as the general partner, in accordance with the pro rata interests, until DCP Partners distributes for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period; |
• | third,to the subordinated unitholders and us as the general partner, in accordance with the pro rata interest, until DCP Partners distributes for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter; |
• | fourth,to all unitholders and us as the general partner, in accordance with the pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter (the First Target Distribution); |
• | fifth,13% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter (the Second Target Distribution); |
• | sixth,23% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter (the Third Target Distribution); and |
• | thereafter,48% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders (the Fourth Target Distribution). |
Distributions of Available Cash after the Subordination Period— DCP Partners’ partnership agreement after adjustment for our relative ownership level requires that DCP Partners make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:
• | first, to all unitholders and us as the general partner, in accordance with the pro rata interests until each unitholder receives a total of $0.4025 per unit for that quarter; |
• | second,13% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter; |
• | third,23% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and |
• | thereafter,48% to us as the general partner, plus our pro rata interest, and the remainder to all unitholders. |
The following table presents cash distributions paid in 2007 ($ in millions, except per unit distribution amounts):
Payment Date | Per Unit Distribution | Total Cash Distribution | ||||
May 15, 2007 | $ | 0.465 | $ | 8.6 | ||
February 14, 2007 | 0.430 | 7.8 |
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9. Member’s Deficit
At June 30, 2007, member’s deficit consisted of our capital account and a note receivable from DCP Midstream, LLC.
As of June 30, 2007, we had a deficit balance of $5.0 million in our member’s deficit account. This negative balance does not represent an asset to us and does not represent obligations by us to contribute cash or other property. The member’s deficit account generally consists of our cumulative share of net income less cash distributions made plus capital contributions made. Cash distributions that we receive during a period from DCP Partners may exceed our interest in DCP Partners’ net income for the period. DCP Partners makes quarterly cash distributions of all of its Available Cash, defined above. Future cash distributions that exceed net income and contributions made will result in an increase in the deficit balance in the member’s deficit account.
10. Risk Management and Hedging Activities
Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We will use the mark-to-market method of accounting for all commodity cash flow hedges beginning in July 2007. As a result, the remaining loss of less than $0.1 million deferred in accumulated other comprehensive income as of June 30, 2007 will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings.
The impact of our derivative activity on our financial position as of June 30, 2007 is insignificant.
Commodity Cash Flow Hedges — We use natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is accumulated in AOCI, and the ineffective portion is recorded in earnings as sales of natural gas, propane, NGLs and condensate. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction will be reclassified to earnings in the same accounts as the item being hedged. As of June 30, 2007, an insignificant amount of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
Commodity Fair Value Hedges — We use fair value hedges to mitigate risk to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) to reduce our exposure to fixed price risk by swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index-based).
All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. During the six months ended June 30, 2007, there were no firm commitments that no longer qualified as fair value hedge items and, therefore, we did not recognize an associated gain or loss.
Commodity Non-Trading Derivative Activity — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs and condensate create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in price variability across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.
Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for
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floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings. We manage our asset-based activities in accordance with our risk management policy, which limits exposure to market risk and requires regular reporting to management of potential financial exposure. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.
In May 2007, we executed a series of financial derivatives to mitigate a portion of the commodity exposure associated with the Southern Oklahoma asset acquisition. We entered into natural gas swap contracts for 1,500 MMBtu/d at $7.54 per MMBtu and into crude oil swap contracts for 650 Bbls/d at $67.60 per Bbl for a term from June 2007 through December 2013. In June 2007, we executed a series of financial derivatives to mitigate a portion of the commodity price exposure associated with our Northern Louisiana system assets. We entered into crude oil swap contracts for 250 Bbls/d at $71.35/Bbl for 2011, 600 Bbls/d at $71.00/Bbl for 2012 and 600 Bbls/d at $71.20/Bbl for 2013. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.
Interest Rate Cash Flow Hedges — During 2006, we entered into interest rate swap agreements to hedge the variable interest rate on $125.0 million of the indebtedness outstanding under our revolving credit facility. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation.
The effective portions of changes in fair value are recognized in AOCI in the unaudited condensed consolidated balance sheet. As of June 30, 2007, an insignificant amount of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
Ineffective portions of changes in fair value are recognized in earnings. The agreements reprice prospectively approximately every 90 days, and expire on December 7, 2010. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 4.68% to 5.08%, and receive interest payments based on the three-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of the agreements.
11. Equity-Based Compensation
On November 28, 2005, the board of directors of the General Partner adopted the LTIP for employees, consultants and directors of the General Partner and its affiliates who perform services for us, effective as of December 7, 2005. Under the LTIP, equity-based instruments may be granted to our key employees. The LTIP provides for the grant of LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the LTIP. Awards that are canceled, forfeited or withheld to satisfy the General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the General Partner’s board of directors.
Performance Units— We have awarded phantom LPUs, or Performance Units, pursuant to the LTIP to certain employees. Performance Units generally vest in their entirety at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over three year performance periods. The final performance payout is determined by the compensation committee of the board of directors of the General Partner. Each Performance Unit includes a DER, which will be paid in cash at the end of the performance period.
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At June 30, 2007, there was approximately $1.8 million of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of 2.1 years. The following table presents information related to the Performance Units:
Units | Grant Date Weighted- Average Price | Measurement Date Price per Unit | ||||||
Outstanding at December 31, 2006 | 23,090 | $ | 26.96 | |||||
Granted | 29,610 | $ | 37.23 | |||||
Outstanding at June 30, 2007 | 52,700 | $ | 32.73 | $ | 46.62 | |||
Expected to vest | 52,700 | $ | 32.73 | $ | 46.62 |
The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.
Phantom Units— In conjunction with our initial public offering, in January 2006 the General Partner’s board of directors awarded phantom LPUs, or Phantom Units, to key employees, and to directors who are not officers or employees of affiliates of the General Partner. Of these Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date, and 5,332 units vest ratably over two years. Each Phantom Unit includes a DER, which is paid quarterly in arrears.
In May 2007, we granted 4,000 Phantom Units under the LTIP to directors who are not officers or employees of affiliates of the General Partner as part of their annual director fees for 2007. These Phantom Units will fully vest six months following the grant date. Each Phantom Unit includes a DER, which is paid quarterly in arrears.
At June 30, 2007, there was approximately $0.6 million of unrecognized compensation expense related to the Phantom Units that is expected to be recognized over a weighted-average period of 1.1 years. The following table presents information related to the Phantom Units:
Units | Grant Date Weighted- Average Price per Unit | Measurement Date Price per Unit | |||||||
Outstanding at December 31, 2006 | 24,700 | $ | 24.05 | ||||||
Granted | 4,000 | $ | 42.69 | ||||||
Vested or paid in cash | (2,668 | ) | $ | 24.05 | |||||
Outstanding at June 30, 2007 | 26,032 | $ | 26.91 | $ | 46.62 | ||||
Expected to vest | 26,032 | $ | 26.91 | $ | 46.62 |
The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.
We intend to settle the awards issued under the LTIP in cash upon vesting, with the exception of the units granted in May 2007. The fair value of all awards is determined based on the closing price of our common units at each measurement date. During the six months ended June 30, 2007, 2,668 awards vested and were settled in cash for $0.1 million.
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12. Commitments and Contingent Liabilities
Litigation
Driver —In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation stems from an ongoing commercial dispute involving the construction of our Wilbreeze pipeline, which was completed in December 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. Driver claims damages in the amount of $2.4 million for breach of contract. We believe Driver’s position in this litigation is without merit and we intend to vigorously defend ourselves against this claim. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.
El Paso — In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of our general partner, DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which is prior to our ownership of this asset. El Paso claims damages, including interest, in the amount of $5.7 million in the litigation, the bulk of which stems from audit claims under our commercial contract for historical periods prior to our ownership of this asset. We will only be responsible for potential payments, if any, for claims that involve periods of time after the date we acquired this asset from DCP Midstream, LLC in December 2005. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.
Other — We are not a party to any other significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our consolidated financial position.
Indemnification — DCP Midstream, LLC has indemnified us for three years after the closing of our initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing of our initial public offering. See the “Indemnification” section of Note 5 for additional details.
13. Subsequent Events
On July 25, 2007, the board of directors of the General Partner declared a quarterly distribution of $0.53 per unit. This quarterly distribution was paid on August 14, 2007 to unitholders of record on August 7, 2007. This distribution of $0.53 per unit exceeds the Fourth Target Distribution level (see Note 8 for discussion of distributions of available cash).
On July 1, 2007, we acquired a 25% limited liability company interest in DCP East Texas Holdings, LLC, a 40% limited liability company interest in Discovery Producer Services LLC and a derivative instrument from DCP Midstream, LLC for aggregate consideration of approximately $271.3 million, consisting of approximately $243.7 million in cash, including $1.3 million for net working capital and other adjustments, the issuance of 620,404 common units valued at $27.0 million and the issuance of 12,661 general partner equivalent units valued at $0.6 million. We financed the cash portion of this transaction with borrowings of $245.9 million under our amended credit facility.
Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We will use the mark-to-market method of accounting for all commodity cash flow hedges beginning in July 2007. As a result, the remaining net loss of less than $0.1 million deferred in AOCI as of June 30, 2007 will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings.
In August 2007, we entered into interest rate swap agreements to convert $200.0 million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps commence on September 21, 2007, expire on June 21, 2012 and re-price prospectively approximately every 90 days. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation.
In conjunction with DCP Midstream, LLC’s acquisition of MEG in August 2007, we acquired certain subsidiaries of MEG from DCP Midstream, LLC for aggregate consideration of approximately $165.0 million, subject to purchase price adjustments. The purchase price consisted of
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approximately $153.8 million of cash and the issuance of 275,735 common units to an affiliate of DCP Midstream, LLC that were valued at approximately $12.0 million. We have incurred post-closing purchase price adjustments to date that include a liability of $9.0 million for net working capital and general and administrative charges. The subsidiaries of MEG own gathering, processing and compression assets in the Piceance and Powder River producing basins. The Piceance Basin assets consist of a 70 percent operating interest in the 31-mile Collbran Valley Gas Gathering system joint venture, which gathers and processes natural gas from over 20,000 dedicated acres in western Colorado. The processing facility capacity is currently being expanded from 60 MMcf/d to 120 MMcf/d. The other partners in the joint venture, Plains Exploration and Delta Petroleum, are also the producers on the system. The Powder River Basin assets include the 1,324-mile Douglas gas gathering system, which gathers approximately 30 MMcf/d of gas and covers more than 4,000 square miles in Wyoming. Also included in the transaction are the idle Painter Unit fractionator and Millis terminal, and associated NGL pipelines in southwest Wyoming. DCP Midstream, LLC will manage and operate these assets on our behalf. We financed this transaction with borrowings under our amended credit facility of $120.0 million, the issuance of common units and cash on hand. In August 2007, we sold 2,380,952 common units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate. In connection with this common unit purchase agreement, we have a registration rights agreement requiring the filing of a shelf registration statement with the Securities and Exchange Commission (“SEC”) to register the units within 90 days of the close of the private placement. In, addition the registration rights agreement requires us to use our commercially reasonable efforts to cause the registration statement to become effective within 180 days of the closing of the private placement. If the registration statement covering the common units is not declared effective by the SEC within 180 days of the closing of the private placement, then we will be liable to the purchasers for liquidated damages of 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for the first 60 days following the 180th day, increasing by an additional 0.25% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the product of the purchase price and the number of registrable securities held by the purchasers per 30-day period.
In August 2007, our Omnibus Agreement with DCP Midstream, LLC was amended to increase the annual fee by $0.6 million for general and administrative expenses payable to DCP Midstream, LLC under the agreement to account for additional services provided to us and extend the term for all general and administrative expenses under the agreement through December 31, 2009. The Omnibus Agreement was further amended in August 2007 to include an additional annual fee of $1.6 million in connection with our acquisition of the MEG subsidiaries, described above.
In September 2007, we received a distribution of $5.0 million for the third quarter of 2007 from DCP East Texas Holdings, LLC.
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