SEC Filing | DCP Midstream, LP

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Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): October 17, 2007

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware

001-32678

03-0567133

(State or other jurisdiction

of incorporation)

(Commission File Number)

(IRS Employer

Identification No.)

370 17^th Street, Suite 2775

Denver, Colorado

80202

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code: (303) 633-2900

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01.

Other Events.

The unaudited condensed consolidated balance sheet of DCP Midstream GP, LP as of June 30, 2007 is filed herewith as Exhibit 99.1 and is incorporated herein by reference. DCP Midstream GP, LP is the general partner of DCP Midstream Partners, LP. The unaudited condensed consolidated balance sheet of DCP Midstream, LLC as of June 30, 2007 is filed herewith as Exhibit 99.2 and is incorporated herein by reference.

Item 9.01.

Financial Statements and Exhibits.

(d)

Exhibits.


Exhibit Number		Description
Exhibit 99.1		Unaudited Condensed Consolidated Balance Sheet of DCP Midstream GP, LP as of June 30, 2007.

Exhibit 99.2		Unaudited Condensed Consolidated Balance Sheet of DCP Midstream, LLC as of June 30, 2007.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	DCP Midstream Partners, LP

	By:	DCP Midstream GP, LP
		its General Partner

	By:	DCP Midstream GP, LLC
		its General Partner

Date: October 17, 2007	/s/ Thomas E. Long
	Name:	Thomas E. Long
	Title:	Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description
Exhibit 99.1		Unaudited Condensed Consolidated Balance Sheet of DCP Midstream GP, LP as of June 30, 2007.

Exhibit 99.2		Unaudited Condensed Consolidated Balance Sheet of DCP Midstream, LLC as of June 30, 2007.

Unaudited Condensed Consolidated Balance Sheet of DCP Midstream GP, LP

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

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.

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.

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.

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;

•

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.

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.

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.

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 210^th 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 the Distributions of Available Cash during the Subordination Period and Distributions 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.

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

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

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.

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 per Unit		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.

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).

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

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.

Unaudited Condensed Consolidated Balance Sheet of DCP Midstream, LLC

Exhibit 99.2

LOGO

DCP Midstream, LLC

Unaudited Condensed Consolidated Balance Sheet

As of June 30, 2007

DCP MIDSTREAM, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

JUNE 30, 2007

(millions)


ASSETS
Current assets:
Cash and cash equivalents	$	140
Short-term investments		560
Accounts receivable:
Customers, net of allowance for doubtful accounts of $3 million		1,048
Affiliates		261
Other		34
Inventories		93
Unrealized gains on mark-to-market and hedging instruments		135
Other		13

Total current assets		2,284

Property, plant and equipment, net		4,079
Investments in unconsolidated affiliates		199
Intangible assets:
Commodity sales and purchases contracts, net		67
Goodwill		421

Total intangible assets		488

Unrealized gains on mark-to-market and hedging instruments		42
Deferred income taxes		5
Other non-current assets		32
Other non-current assets—affiliates		48

Total assets	$	7,177


LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,657
Affiliates		92
Other		53
Unrealized losses on mark-to-market and hedging instruments		135
Distributions payable to members		137
Accrued interest payable		46
Accrued taxes		40
Other		118

Total current liabilities		2,278

Deferred income taxes		17
Long-term debt		2,090
Unrealized losses on mark-to-market and hedging instruments		56
Other long-term liabilities		274
Non-controlling interests		150
Commitments and contingent liabilities
Members’ equity:
Members’ interest		2,107
Retained earnings		211
Accumulated other comprehensive loss		(6	)

Total members’ equity		2,312

Total liabilities and members’ equity	$	7,177

See Notes to Unaudited Condensed Consolidated Balance Sheet.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2007

1. General and Summary of Significant Accounting Policies

Basis of Presentation — DCP Midstream, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs.

We formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. DCP Partners completed their initial public offering in December 2005. As of June 30, 2007, we own approximately 35.5% of the limited partnership interests in DCP Partners and a 1.7% general partnership interest, as well as incentive distribution rights that entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved. As the general partner of DCP Partners, we have responsibility for its operations. Since we exercise control over DCP Partners, we account for them as a consolidated subsidiary.

Prior to January 2, 2007, we were owned 50% by Duke Energy Corporation, or Duke Energy. On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For periods prior to January 2, 2007 included in this report, references to Spectra Energy are interchangeable with Duke Energy. Effective January 2, 2007, Spectra Energy refers to the newly formed public company.

We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

This unaudited condensed consolidated balance sheet reflects all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position for the interim period. Certain information and notes normally included in our annual balance sheet have been condensed in or omitted from this interim balance sheet. This unaudited condensed consolidated balance sheet should be read in conjunction with our consolidated balance sheet and notes thereto for the year ended December 31, 2006.

The unaudited condensed consolidated balance sheet includes the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

Use of Estimates — Conformity with accounting principles generally accepted in the United States of America, or 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 be different from those estimates.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

Distributions — Under the terms of the Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each member’s tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. The capital accounts are maintained at 50% for each member. During the six months ended June 30, 2007 we paid distributions of $240 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. The LLC Agreement restricts payment of dividends except with the approval of both members. During the six months ended June 30, 2007, we paid dividends of $110 million to the members, allocated in accordance with their respective ownership percentages.

DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our limited partner interest in DCP Partners primarily consists of subordinated units, as well as common and Class C units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. 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 DCP Partners’ 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 DCP Partners’ partnership agreement are satisfied. During the six months ended June 30, 2007, DCP Partners paid distributions of approximately $9 million to its public unitholders. We hold a 1.7% general partnership interest, as well as incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

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 $192 million of gain on sale of common units of DCP Partners, which is included in other long-term liabilities in the unaudited condensed consolidated balance sheet. This gain is comprised of approximately $43 million related to DCP Partners’ private placement in June 2007 and approximately $149 million related to DCP Partners’ initial public offering in December 2005. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

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 a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. 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.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

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.

2. Acquisitions

Acquisitions

Acquisition of Various Gathering, Pipeline and Compression Assets — In July 2007, we contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings, LLC, our 40% limited liability company interest in Discovery Producer Services LLC, and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas Holdings, LLC, while third parties still own the other 60% limited liability interest in Discovery Producer Services LLC. DCP Partners financed the cash portion of this transaction with borrowings under its existing credit facility. We will continue to operate these assets and these assets will continue to be included in our financial statements, along with DCP Partners.

In May 2007, we agreed to acquire the stock of Momentum Energy Group, Inc., or MEG, for $635 million, subject to closing adjustments. This transaction closed in the third quarter of 2007. MEG owns assets in the Fort Worth, Piceance and Powder River producing basins. Concurrent with this agreement, DCP Partners entered into an agreement with us to acquire certain subsidiaries of MEG from us for $165 million, subject to closing adjustments. In May 2007, in connection with this transaction, 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 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 Securities and Exchange Commission, or 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. We funded our portion of this acquisition with a 364-day bridge loan for $450 million, as well as cash on hand. DCP Partners financed their portion of the acquisition with cash on hand, common units and proceeds from their credit facility.

In May 2007, DCP Partners acquired certain gathering and compression assets located in southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181 million.

In the fourth quarter of 2005, we entered into an agreement to purchase certain pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million, which are regulated by the Federal Energy Regulatory Commission, or FERC. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate as an intrastate pipeline. This acquisition is expected to close in 2008.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

3. Agreements and Transactions with Affiliates

Spectra Energy

Commodity Transactions — We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide services to Spectra Energy in the ordinary course of business.

Included in the unaudited condensed consolidated balance sheet in other non-current assets—affiliates as of June 30, 2007, are insurance recovery receivables of $48 million, and included in accounts receivable—affiliates as of June 30, 2007, are other receivables of $2 million. Prior to January 2, 2007, these receivables were from an insurance provider that is a subsidiary of Duke Energy. In connection with the Spectra spin, Spectra Energy is responsible for these insurance liabilities.

Duke Energy

Services Agreement — Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

In connection with the Spectra spin, we are in the process of transferring responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transitioning these services either to Spectra Energy or to third party service providers.

ConocoPhillips

Long-term NGLs Purchases Contract and Transactions — We sell a portion of our residue gas and NGLs to ConocoPhillips and ChevronPhillips Chemical Company LLC, or CP Chem, a 50% equity investment of ConocoPhillips. In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreements, or the NGL Agreements, with ConocoPhillips and CP Chem, ConocoPhillips and CP Chem have the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The NGL Agreements also grant ConocoPhillips and CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary terms of the agreements are effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

Transactions with other unconsolidated affiliates

We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.

Estimates related to affiliates

Accounts receivable and accounts payable related to goods and services provided or used but not invoiced is estimated and recorded each month. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to quarter end relating to estimated accounts receivable and accounts payable recorded at June 30, 2007.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

4. Inventories

Inventories were as follows as of June 30, 2007:


	(millions)
Natural gas held for resale	$	45
NGLs		48

Total inventories	$	93

5. Financing

Long-term debt was as follows at June 30, 2007:


	Principal/ Discount (millions)
Debt securities:
Issued August 2000, interest at 7.875% payable semiannually, due August 2010	$	800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011		250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015		200
Issued August 2000, interest at 8.125% payable semiannually, due August 2030		300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036		300
DCP Partners’ credit facility revolver, weighted-average interest rate of 5.77%, due June 2012		249
Fair value adjustments related to interest rate swap fair value hedges		(3	)
Unamortized discount		(6	)

Long-term debt	$	2,090

Debt Securities — In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007.

The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.

Credit Facilities with Financial Institutions — We have a $450 million revolving credit facility, or the Facility, which is used to support our commercial paper program, and for working capital and other general corporate purposes. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity to April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility may be used for letters of credit. As of June 30, 2007, there were no borrowings or commercial paper outstanding, and there were approximately $5 million in letters of credit outstanding.

On June 21, 2007, DCP Partners entered into the Amended and Restated Credit Agreement, or DCP Partners’ Amended Credit Agreement, that replaced their existing credit agreement, or DCP Partners’ Credit Agreement, which consists of a $600 million revolving credit facility and a $250 million term loan facility. At June 30, 2007, DCP Partners had less than $1 million of letters of credit outstanding. In June 2007, DCP Partners incurred $1 million of debt issuance costs associated with DCP Partners’ Amended Credit Agreement. These expenses are deferred as other non-current assets in the unaudited condensed consolidated balance sheet and will be amortized over the term of DCP Partners’ Amended Credit Agreement.

Under DCP Partners’ 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 the leverage level or credit rating. As of June 30, 2007, the revolving credit facility bears interest at a weighted-average rate of 5.77% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on the 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%.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

DCP Partners’ Amended Credit Agreement requires DCP Partners to maintain a leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, in each case as is defined by DCP Partners’ 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. DCP Partners’ Amended Credit Agreement also requires DCP Partners to maintain an interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense, in each case as is defined by DCP Partners’ 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, DCP Partners entered into a two-month bridge loan, or the Bridge Loan, which provided for borrowings up to $100 million, and had terms and conditions substantially similar to those of DCP Partners’ Credit Agreement. In conjunction with DCP Partners entering into the Bridge Loan, DCP Partners’ Credit Agreement was amended to provide for additional unsecured indebtedness, of an amount not to exceed $100 million, which was due and payable no later than August 9, 2007. DCP Partners used borrowings of $88 million from the Bridge Loan to partially fund the acquisition of assets from Anadarko. The remaining $12 million available for borrowing on the Bridge Loan was not utilized. DCP Partners used a portion of the net proceeds of a private placement of limited partner units to extinguish the $88 million outstanding on the Bridge Loan.

6. Income Taxes

We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns.

In May 2006, the State of Texas enacted a margin-based franchise tax law that replaces the existing franchise tax. This tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The tax will be based on the margin earned during the prior calendar year.

The margin has been defined as revenues less cost of goods sold and certain other deductible expenses. The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas.

The Texas margin tax is considered an income tax. GAAP requires that deferred taxes be adjusted upon enactment of new tax law, which occurred in 2006. Accordingly, we recorded a deferred tax liability of $18 million during the second quarter of 2006. The deferred tax liability is recorded as non-current in the unaudited condensed consolidated balance sheet as of June 30, 2007.

Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.

7. Commitments and Contingent Liabilities

Litigation — The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

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 DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. 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.

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

In May 2007, a lawsuit was filed alleging migration of acid gas from a storage formation into a third party producing formation, which was a continuation from the demand we received in November 2006. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.

Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated financial position.

General Insurance — Midstream’s insurance coverage is carried with an affiliate of ConocoPhillips and third party insurers, and includes: (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) excess liability insurance above the established primary limits for commercial general liability and automobile liability insurance; and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, windstorms, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. Also, during the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages were covered by our insurance, subject to applicable deductibles. The financial impact of hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated financial position. Insurance recovery receivables and business interruption recoveries related to these hurricanes are discussed in Note 3.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated financial position.

On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at six of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions beginning January 2001, and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.

Other — In June 2007, DCP Partners entered into a private placement agreement with a group of institutional investors for $130 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $129 million, net of offering costs. In connection with this 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 Securities and Exchange Commission 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 to be issued in connection with 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 DCP Partners will be liable to the institutional investors for liquidated damages of 0.25% of

DCP MIDSTREAM, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — Continued

AS OF JUNE 30, 2007

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.

8. Guarantees and Indemnifications

We have signed a corporate guaranty, pursuant to which we are the guarantor of a maximum of less than $1 million of construction obligations as of June 30, 2007. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated financial position.

We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities.

9. Subsequent Events

In July 2007, we contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings, LLC, our 40% limited liability company interest in Discovery Producer Services LLC, and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas Holdings, LLC, while third parties still own the other 60% limited liability interest in Discovery Producer Services LLC. DCP Partners financed the cash portion of this transaction with borrowings under its existing credit facility. We will continue to operate these assets and these assets will continue to be included in our financial statements, along with DCP Partners. In connection with this transaction, in July 2007, we paid dividends of $243 million to our members, allocated in accordance with their respective ownership percentages.

On July 25, 2007, the board of directors of DCP Partners’ general partner declared a quarterly distribution of $0.53 per unit, payable on August 14, 2007, to unitholders of record on August 7, 2007.

Effective July 1, 2007, DCP Partners elected to discontinue using the hedge method of accounting for its commodity cash flow hedges. DCP Partners 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 $2 million deferred in accumulated other comprehensive loss as of June 30, 2007 will be reclassified to sales of natural gas and petroleum products, through December 2011, as the hedged transactions impact earnings.

In August 2007, DCP Partners entered into interest rate swap agreements to convert $200 million of the indebtedness on their 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 August 2007, we completed the acquisition of the stock of MEG for $635 million, subject to purchase price adjustments. In conjunction with the closing of this acquisition, DCP Partners acquired certain of the MEG subsidiaries from us for $165 million, subject to purchase price adjustments. DCP Partners has incurred post-closing purchase price adjustments to date that include a liability of $9 million for net working capital and general and administrative charges. We financed our portion of the acquisition with a 364-day bridge loan for $450 million, as well as cash on hand. DCP Partners financed their portion of the acquisition with cash on hand, common units and proceeds from their credit facility.