Condensed Consolidated Balance Sheet of DCP Midstream GP, LP as of June 30, 2009

EX-99.1 6 dex991.htm CONDENSED CONSOLIDATED BALANCE SHEET OF DCP MIDSTREAM GP, LP AS OF JUNE 30, 2009 Condensed Consolidated Balance Sheet of DCP Midstream GP, LP as of June 30, 2009

Exhibit 99.1

DCP Midstream GP, LP

(A Delaware Limited Partnership)

Unaudited Condensed Consolidated Balance Sheet

As of June 30, 2009

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET OF

DCP MIDSTREAM GP, LP

TABLE OF CONTENTS


		Page
Unaudited Condensed Consolidated Balance Sheet as of June 30, 2009		2
Notes to Unaudited Condensed Consolidated Balance Sheet		3

DCP MIDSTREAM GP, LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET


	June 30, 2009
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	4.6
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.8 million		35.2
Affiliates		57.6
Inventories		16.9
Unrealized gains on derivative instruments		5.9
Other		1.7

Total current assets		121.9
Restricted investments		35.1
Property, plant and equipment, net		973.9
Goodwill		89.1
Intangible assets, net		46.0
Equity method investments		117.0
Unrealized gains on derivative instruments		3.8
Other long-term assets		4.6

Total assets	$	1,391.4

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	57.3
Affiliates		13.4
Unrealized losses on derivative instruments		25.7
Accrued interest payable		0.8
Other		33.3

Total current liabilities		130.5
Long-term debt		638.0
Unrealized losses on derivative instruments		43.6
Other long-term liabilities		13.8

Total liabilities		825.9

Commitments and contingent liabilities
Equity:
Partners’ equity		183.9
Note receivable from DCP Midstream, LLC		(183.0	)
Accumulated other comprehensive loss		(0.6	)

Total partners’ equity		0.3
Noncontrolling interests		565.2

Total equity		565.5

Total liabilities and equity	$	1,391.4

See accompanying notes to condensed consolidated balance sheet.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2009

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 interests are owned by DCP Midstream, LLC and DCP Midstream GP, LLC. We own approximately a 1% general partner interest and a 1% limited partner 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, producing, transporting, storing and selling propane and transporting and selling natural gas liquids, or NGLs, and condensate. 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; our Southern Oklahoma system; our limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system and a 70% interest in our Colorado system; our 50.1% interest in our East Texas system; our Michigan systems; our wholesale propane logistics business; and our NGL transportation pipelines.

In April 2009, DCP Partners acquired an additional 25.1% interest in DCP East Texas Holdings, LLC, or East Texas, and a fixed price natural gas liquids derivative by NGL component for the period of April 2009 to March 2010, or NGL Hedge, from DCP Midstream, LLC, in a transaction among entities under common control. Our East Texas system includes a natural gas processing complex with a total capacity of 780 MMcf/d and a NGL fractionator, which serves as the processing facility for our 900-mile gathering system, as well as third party gathering systems. The complex is adjacent to our Carthage Hub, which delivers gas to interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas. Transfers of net assets or exchanges of units between entities under common control are accounted for as if the transfer occurred at the beginning of the period. Prior to this transaction, DCP Partners owned a 25.0% limited liability company interest in East Texas, which was accounted for under the equity method of accounting. Subsequent to this transaction DCP Partners own a 50.1% interest in East Texas. Accordingly, following this transaction, East Texas is accounted for as a consolidated entity. Approximately 98% of the $18.3 million deficit purchase price under the historical basis of the net acquired assets and the $49.7 million of DCP Partners’ Class D units issued as consideration for this transaction were recorded as an increase in noncontrolling interests.

The condensed consolidated balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The 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 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 consolidated balance sheet as transactions between affiliates.

The 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 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, 2008 included as Exhibit 99.1 to DCP Partners’ Form 10-K filed with the Securities and Exchange Commission, or SEC, on March 5, 2009.

2.	Summary of Significant Accounting Policies

Accounting for Sales of Units by a Subsidiary — Prior to our adoption of SFAS No.160 ‘Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin No. 51,’ or SFAS 160, on January 1, 2009, we accounted 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. Effective upon the adoption of SFAS No. 160, the sale of units by a subsidiary are required to be accounted for as equity transactions. As a result of the adoption of SFAS No.160 a $5.4 million deferred gain on the sale of common units in DCP Partners was reclassified from other long-term liabilities to partners’ equity in the condensed consolidated balance sheet.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

3.	Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standards, or SFAS, No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a Replacement of FASB Statement No. 162,” or SFAS 168 — In June 2009, the FASB issued SFAS 168, which establishes the FASB Accounting Standards Codification, or the Codification, as the source of authoritative U.S. Generally Accepted Accounting Principles, or GAAP. The Codification supersedes all existing non-SEC accounting and reporting standards. This SFAS becomes effective for us for annual and interim periods beginning after September 15, 2009 and will not affect our condensed consolidated financial position as a result of adoption.

SFAS No. 167 “Amendments to FASB Interpretation No. 46(R),” or SFAS 167 — In June 2009, the FASB issued SFAS 167, which requires entities to perform additional analysis of their variable interest entities and consolidation methods. This SFAS becomes effective for us on January 1, 2010 and we are in the process of assessing the impact of this guidance on our condensed consolidated financial position.

SFAS No. 165 “Subsequent Events,” or SFAS 165 — In May 2009, the FASB issued SFAS 165, which sets forth the recognition and disclosure requirements for events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted SFAS 165 effective June 30, 2009, and there was no effect on our condensed consolidated financial position as a result of adoption. All appropriate disclosure of subsequent events is made within the footnotes.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133,” or SFAS 161 — In March 2008, the FASB issued SFAS 161, which requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of SFAS 161 effective January 1, 2009, and have included all required disclosures in this filing. SFAS 161 impacts only disclosures so there was no effect on our condensed consolidated financial position as a result of adoption.

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin No. 51,” or SFAS 160 — In December 2007, the FASB issued SFAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We adopted SFAS 160 effective January 1, 2009, which required retrospective restatement of our condensed consolidated financial statements for all periods presented in this filing. As a result of adoption, we have reclassified the deferred gain of approximately $5.4 million, relating to the sale of units by a subsidiary from long-term liabilities to partners’ equity in the condensed consolidated balance sheet. We have reclassified our noncontrolling interest on our condensed consolidated balance sheets, from a component of liabilities to a component of equity.

SFAS No. 141(R) “Business Combinations (revised 2007),” or SFAS 141(R) — In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination subsequent to January 1, 2009 to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. We adopted SFAS 141(R) effective January 1, 2009, and will account for all transactions with closing dates subsequent to adoption in accordance with the provisions of this standard.

SFAS No. 157 “Fair Value Measurements,” or SFAS 157 — In September 2006, the FASB issued SFAS 157, which we adopted on January 1, 2008 for all financial assets and liabilities. Pursuant to FASB Staff Position, or FSP, 157-2, the FASB issued a partial deferral, ending on December 31, 2008, of the implementation of SFAS 157 as it relates to all nonfinancial assets and liabilities where fair value is the required measurement attribute by other accounting standards. Effective January 1, 2009, we adopted SFAS

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

157 for all nonfinancial assets and liabilities. There was no effect on our condensed consolidated financial position, and we have included all required disclosures as a result of the adoption of this standard relative to nonfinancial assets and liabilities. The provisions of SFAS 157 will be applied at such time a fair value measurement of a nonfinancial asset or nonfinancial liability is required, which may result in a fair value that is different than would have been calculated prior to the adoption of SFAS 157.

FSP No. SFAS 142-3 “Determination of the Useful Life of Intangible Assets,” or FSP 142-3 — In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset. We adopted FSP 142-3 on January 1, 2009. As a result of acquisitions, we have intangible assets for customer contracts and related relationships in our condensed consolidated balance sheets. Generally, costs to renew or extend such contracts are not significant, and are expensed as incurred. During the current quarter, there were no contracts that were recognized as intangible assets that were renewed or extended.

FSP No. SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” or FSP 157-4 — In April 2009, the FASB issued FSP 157-4, which provides additional guidance on the valuation of assets or liabilities that are held in markets that have seen a significant decline in activity. While this FSP does not change the overall objective of determining fair value, it emphasizes that in markets with significantly decreased activity and the appearance of non-orderly transactions, an entity may employ multiple valuation techniques, to which significant adjustments may be required, to determine the most appropriate fair value. Certain of the markets in which we transact have seen a decrease in overall volume; however, we believe that these markets continue to provide sufficient liquidity such that transactions are executed in an orderly manner at fair value. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated financial position.

FSP No. SFAS 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1 — In April 2009, the FASB issued FSP 141(R)-1, which provides additional guidance on the valuation of assets and liabilities assumed in a business combination that arise from contingencies, which would otherwise be subject to the provisions of SFAS No. 5 “Accounting for Contingencies,” or SFAS 5. This FSP emphasizes the guidance set forth in SFAS 141(R) that assets and liabilities assumed in a business combination that have an estimated fair value should be recorded at the time of acquisition. Assets and liabilities where the fair value may not be determinable during the measurement period will continue to be recognized pursuant to SFAS 5. This FSP becomes effective for us for business combinations with closing dates subsequent to January 1, 2009. During the first six months of 2009 we did not have any transactions that were accounted for as business combinations. We will account for any business combinations with closing dates subsequent to the effective date in accordance with this new guidance.

FSP No. SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” — This FSP was issued in April 2009, and requires disclosure of summarized financial information for financial instruments accounted for under SFAS No. 107 “Disclosures about Fair Value of Financial Instruments,” or SFAS 107. We have instruments that are subject to the fair value disclosure requirements of SFAS 107, and are subject to the revised disclosure provisions of this FSP. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated financial position.

FSP No. SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” — This FSP was issued in April 2009, and amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated financial position.

Emerging Issues Task Force, or EITF, 08-6 “Equity Method Investment Accounting Considerations,” or EITF 08-6 — In November 2008 the EITF issued EITF 08-6. Although the issuance of SFAS 141(R) and SFAS 160 were not intended to reconsider the accounting for equity method investments, the application of the equity method is affected by the issuance of these standards. This issue addresses a) how the initial carrying value of an equity method investment should be determined; b) how impairment assessment of an underlying indefinite-lived intangible asset of an equity method investment should be performed; c) how an equity method investee’s issuance of shares should be accounted for; and d) how to account for a change in an investment from the equity method to the cost method. This issue became effective for us on January 1, 2009, and although it has not impacted the manner in which we apply equity method accounting, this guidance will be considered on a prospective basis to transactions with equity method investees.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

4.	Acquisitions

Gathering and Compression Assets

On April 1, 2009, DCP Partners acquired an additional 25.1% interest in East Texas and the NGL Hedge from DCP Midstream, LLC, for aggregate consideration of 3,500,000 Class D units valued at $49.7 million.

5.	Agreements and Transactions with Affiliates

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 certain costs incurred and centralized corporate functions performed by DCP Midstream, LLC on our behalf. Under the Omnibus Agreement, DCP Midstream, LLC has issued parental guarantees, totaling $43.0 million at June 30, 2009, to certain counterparties to our commodity derivative instruments.

Other Agreements and Transactions with DCP Midstream, LLC

In conjunction with DCP Partners acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, DCP Partners entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain East Texas capital projects as defined in the Contribution Agreement from April 1, 2009 for a period not to exceed three years. DCP Midstream, LLC made additional capital contributions of $11.5 million during the three months ended June 30, 2009 to East Texas for these capital projects.

On February 11, 2009, we announced that our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, had been temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. DCP Partners is actively pursuing full reimbursement of costs and lost margin associated with the incident from the responsible third party. We also have insurance covering these amounts, net of applicable deductibles. Following this incident, DCP Midstream, LLC has agreed to reimburse us 25% of any claims received as reimbursement of costs and lost margin associated with the incident, from the responsible third party. DCP Midstream, LLC will pay 75% of costs related to the incident.

On February 25, 2009, DCP Partners entered into a Contribution Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC will contribute an additional 25.1% interest in East Texas to DCP Partners in exchange for 3,500,000 DCP Partners Class D units, providing DCP Partners with a 50.1% interest in East Texas. This transaction closed in April 2009. Accordingly, following this transaction, East Texas is accounted for as a consolidated entity.

We sell a portion of our residue gas and NGLs to, purchase natural gas and other petroleum products from, and provide gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase commodities from and sell commodities to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf.

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 us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Pelico has certain contractual relationships that define how natural gas is bought and sold between us and DCP Midstream, LLC.

In January 2009, we amended our Pelico gas purchase and sales agreement with DCP Midstream, LLC. As a result of the amendment, our purchases from DCP Midstream, LLC occur upstream of Pelico, rather than at the inlet of Pelico. We assumed from DCP Midstream, LLC a firm transportation agreement with an affiliate to transport our natural gas purchases from DCP Midstream, LLC to Pelico. In addition, historically, the sales price of a portion of the natural gas we sold to DCP Midstream, LLC was determined based on the price at which we purchased the natural gas from DCP Midstream, LLC plus a portion of the index differential between upstream sources to certain downstream indices with a maximum and minimum differential. The pricing methodology has changed as 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 we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

•

For volumes supplied to certain industrial end users and any volumes in excess of the on-system demand, DCP Midstream, LLC will purchase natural gas from us and sell it to certain industrial end users, or transport it to sales points at an index-based price, less contractually agreed-to marketing fees.

In conjunction with DCP Partners acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, DCP Partners entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to DCP Partners as reimbursement for certain Discovery capital projects, which were forecasted to be completed prior to DCP Partners acquisition of a 40% limited liability company interest in Discovery. DCP Midstream, LLC made capital contributions to DCP Partners during the six months ended June 30, 2009 of $0.7 million to reimburse DCP Partners for these capital projects.

In conjunction with our acquisition of East Texas and Discovery in July 2007 DCP Partners entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for 25% of certain East Texas capital expenditures, defined in the agreement, from July 1, 2007, through completion of the capital projects for a period not to exceed three years. DCP Midstream, LLC made additional capital contributions to East Texas for these capital projects of $6.2 million during the six months ended June 30, 2009.

DCP Midstream, LLC has issued additional parental guarantees outside of the Omnibus Agreement totaling $40.0 million at June 30, 2009, to certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties.

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 partners’ 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, 2009. All interest income earned under the note has been distributed to DCP Midstream, LLC.

Spectra Energy

We purchase a portion of our propane from and market propane on behalf of Spectra Energy. We anticipate continuing to purchase propane from and market propane on behalf of Spectra Energy in the ordinary course of business.

During 2008, we entered into a propane supply agreement with Spectra Energy. This agreement, effective May 1, 2008 and terminating April 30, 2014, provides us propane supply at our marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. This contract replaces the supply provided under a contract with a third party that was terminated for non-performance during 2008.

ConocoPhillips

We have multiple agreements whereby we provide a variety of services for ConocoPhillips and its affiliates. The agreements include fee-based and percent-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 $0.7 million of capital reimbursements during the six months ended June 30, 2009.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

We had balances with affiliates as follows:


	June 30, 2009
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	55.0
Accounts payable	$	11.6
Unrealized gains on derivative instruments—current	$	1.0
Unrealized losses on derivative instruments—current	$	(1.0	)
Spectra Energy:
Accounts receivable	$	1.2
Accounts payable	$	1.3
ConocoPhillips:
Accounts receivable	$	1.4
Accounts payable	$	0.5

6.	Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:


	Depreciable Life	June 30, 2009
		(Millions)
Gathering systems	15 — 30 Years	$	576.5
Processing plants	25 — 30 Years		407.6
Terminals	25 — 30 Years		28.9
Transportation	25 — 30 Years		217.5
Underground storage	20 — 50 Years		0.1
General plant	3 — 5 Years		15.0
Construction work in progress			89.1

Property, plant and equipment			1,334.7
Accumulated depreciation			(360.8	)

Property, plant and equipment, net		$	973.9

The above amount includes accrued capital expenditures of $18.7 million as of June 30, 2009, which is included in other current liabilities in the condensed consolidated balance sheet.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

7.	Equity Method Investments

The following table summarizes our equity method investments:


	Percentage of Ownership as of June 30, 2009		Carrying Value as of June 30, 2009
			(Millions)
Discovery Producer Services LLC	40	%	$	110.3
Black Lake Pipe Line Company	45	%		6.5
Other	50	%		0.2

Total equity method investments			$	117.0

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $38.5 million at June 30, 2009, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $5.9 million at June 30, 2009, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

In the second quarter of 2009, Discovery’s LLC agreement was amended to calculate available cash based on cash on hand at the end of the month preceding the end of each calendar quarter (e.g. May 31 for the second quarter) and to require distribution of available cash by the end of each calendar quarter. Prior to this amendment, Discovery calculated available cash based on cash on hand at the end of each calendar quarter and made the related distribution within 30 days of the end of each calendar quarter.

The following summarizes balance sheet information of our equity method investments:


	June 30, 2009
	(Millions)
Current assets	$	66.5
Long-term assets		389.5
Current liabilities		(40.1	)
Long-term liabilities		(22.1	)

Net assets	$	393.8

8.	Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities, as well as short-term and restricted investments, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. In the event that listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other marketplace participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

•

Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

•

Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•

Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.

Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and a market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

We have interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our floating rate debt for fixed rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a significant portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Short-Term and Restricted Investments

We are required to post collateral to secure the term loan portion of our credit facility, and may elect to invest a portion of our available cash balances in various financial instruments such as commercial paper and money market instruments. The money market instruments are generally priced at acquisition cost, plus accreted interest at the stated rate, which approximates fair value, without any additional adjustments. Given that there is no observable exchange traded market for identical money market securities, we have classified these instruments within Level 2. Investments in commercial paper are priced using a yield curve for similarly rated instruments, and are classified within Level 2. As of June 30, 2009, nearly all of our short-term and restricted investments were held in the form of money market securities. By virtue of our balances in these funds on September 19, 2008, all of these investments are eligible for, and the funds are participating in, the U.S. Treasury Department’s Temporary Guarantee Program for Money Market Funds.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations on our leased property, plant and equipment. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

The following table presents the financial instruments carried at fair value as of June 30, 2009, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:


	Quoted Market Prices In Active Markets (Level 1)		Internal Models With Significant Observable Market Inputs (Level 2)			Internal Models With Significant Unobservable Market Inputs (Level 3)			Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	4.7		$	1.2		$	5.9
Long-term assets:
Restricted investments	$	—	$	35.1		$	—		$	35.1
Commodity derivatives (b)	$	—	$	2.9		$	—		$	2.9
Interest rate derivatives (b)	$	—	$	0.9		$	—		$	0.9
Current liabilities (c):
Commodity derivatives	$	—	$	(6.9	)	$	(0.1	)	$	(7.0	)
Interest rate derivatives	$	—	$	(18.7	)	$	—		$	(18.7	)
Long-term liabilities (d):
Commodity derivatives	$	—	$	(29.9	)	$	(0.9	)	$	(30.8	)
Interest rate derivatives	$	—	$	(12.8	)	$	—		$	(12.8	)

(a)	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheet.

(b)	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheet.

(c)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheet.

(d)	Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheet.

Changes in Level 3 Fair Value Measurements

The table below illustrates a rollforward of the amounts included in our condensed consolidated balance sheet for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers In/Out of Level 3” caption.

We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009


	Balance at December 31, 2008		Net Realized and Unrealized Gains (Losses) Included in Earnings			Transfers In/ Out of Level 3 (a)		Purchases, Issuances and Settlements, Net		Balance at June 30, 2009
	(Millions)
Commodity derivative instruments:
Current assets	$	0.3	$	(2.7	)	$	—	$	3.6	$	1.2
Long-term assets	$	1.7	$	(1.7	)	$	—	$	—	$	—
Current liabilities	$	—	$	(0.1	)	$	—	$	—	$	(0.1	)
Long-term liabilities	$	—	$	(0.9	)	$	—	$	—	$	(0.9	)

(a)	Amounts transferred in are reflected at fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

Debt

Long-term debt was as follows:


	June 30, 2009
	(Millions)
Revolving credit facility, weighted-average interest rate of 1.03%, due June 21, 2012 (a)	$	603.0
Term loan facility, interest rate of 0.42%, due June 21, 2012		35.0

Total long-term debt (b)	$	638.0

(a)	$575.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%, for a net effective rate of 4.47% on the $603.0 million of outstanding debt under our revolving credit facility as of June 30, 2009.

(b)	The term loan facility is fully secured by restricted investments.

Credit Agreement

We have an $824.6 million 5-year credit agreement that matures June 21, 2012, or the Credit Agreement, which consists of:

•

a $789.6 million revolving credit facility; and

•

a $35.0 million term loan facility.

The above amounts are net of non-participation by Lehman Brothers Commercial Bank. At June 30, 2009 we had $0.3 million of letters of credit outstanding under the Credit Agreement. Outstanding balances under the term loan facility are fully collateralized by investments in high-grade securities, which are classified as restricted investments in the accompanying condensed consolidated balance sheets. As of June 30, 2009 the available capacity under the revolving credit facility was $188.5 million.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

Other Agreements

As of June 30, 2009, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million, which reduces the amount of cash we may be required to post as collateral. We pay a fee of 0.8% per annum on this letter of credit. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under the Credit Agreement.

10.

Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures by using physical and financial derivative instruments. We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following briefly describes each of the risks that we manage.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering and processing services, we may receive fees or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Additionally, given the limited depth of the NGL derivatives market, we primarily utilize crude oil swaps and following DCP Partners acquisition of the NGL Hedge on April 1, 2009, NGL derivatives to mitigate a significant portion of our commodity price exposure for propane and heavier NGLs. Historically, there has been a relationship between NGL prices and crude oil prices and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps to mitigate a portion of NGL price risks. As a result of the current movements in the relationship of NGL prices to crude oil prices outside of recent historical ranges, we have additional exposure to changes in the relationship. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2014 with natural gas, crude oil and NGL derivative instruments. These transactions are primarily accomplished through the use of forward contracts, swap futures that effectively exchange our floating rate price risk for a fixed rate, but the type of instrument that we use to mitigate our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in earnings.

Our Wholesale Propane Logistics segment 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. 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. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. While the majority of our sales and purchases in this segment are index-based, 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. In such cases, we may manage this risk with derivatives that 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 transactions are not designated as hedging instruments for accounting purposes and the change in value is reflected in earnings.

Furthermore, with respect to our Pelico system, we may enter into financial derivatives to lock in price differentials across the system and connected storage to maximize its value. This objective may be achieved through the use of physical purchases or sales of gas that are accounted for under accrual accounting. While the physical purchase or sale of gas transactions are accounted for under accrual accounting, the swaps are not designated as hedging instruments for accounting purposes and any change in fair value of these instruments is reflected in the current period in earnings.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives that manage our commodity price risk. We have used the mark-to-market method of accounting for all derivatives that manage our commodity price risk since July 2007, thus changes in fair value are recorded directly to earnings. Derivative contracts that were put in place prior to this date may have been designated as cash flow or fair value hedges, and are described below.

Commodity Cash Flow Hedges — We used NGL, natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. Prior to July 1, 2007, the effective portion of the change in fair value of a derivative designated as a cash flow hedge was recorded in accumulated other comprehensive income, or AOCI. During the period in which the hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were reclassified to earnings in the same accounts as the item being hedged.

Given our election to discontinue using the hedge method of accounting, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings. Subsequent to July 1, 2007, the changes in fair value of financial derivatives are included in earnings.

Commodity Fair Value Hedges — Historically, we used 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. As described above relative to our Wholesale Propane Logistics segment, we may have hedged producer price locks, or fixed price gas purchases, to reduce our cash flow exposure to fixed price risk by swapping the fixed price risk for a floating price position linked to the New York Mercantile Exchange or an index-based position.

Interest Rate Risk

Interest Rate Cash Flow Hedges — We mitigate a portion of our interest rate risk with interest rate swaps, which reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swap agreements convert the interest rate associated with an aggregate of $575.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All 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 condensed consolidated balance sheets and are reclassified into earnings as the hedged transactions impact earnings. The effect that these swaps have on our condensed consolidated financial statements, as well as the effect that is expected over the upcoming 12 months is summarized in the charts below. 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. $425.0 million of the agreements reprice prospectively approximately every 90 days and the remaining $150.0 million of the agreements reprice prospectively approximately every 30 days. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 2.26% to 5.19%, and receive interest payments based on the three-month and one-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.

•

If we were to have an effective event of default under our credit agreement, that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

•

In the event that DCP Midstream, LLC was to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties may have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our credit agreement. As of June 30, 2009, we are not a party to any agreements that would be subject to these provisions other than our credit agreement.

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Depending upon the movement of commodity prices, each of our individual contracts with counterparties to our commodity derivative instruments are in either a net asset or net liability position. As of June 30, 2009, we had approximately $36.7 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of June 30, 2009 if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of June 30, 2009, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $28.9 million.

As of June 30, 2009 our interest rate swaps were in a net liability position of approximately $30.6 million, of which, the entire amount is subject to credit-risk related contingent features. If we were to have a default of any of our covenants to our credit agreement, that occurs and is continuing, the counterparties to our swap instruments may have the right to request that we net settle the instrument in the form of cash.

Collateral

As of June 30, 2009, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million. This letter of credit reduces the amount of cash we may be required to post as collateral. As of June 30, 2009, we had no cash collateral posted with counterparties to our commodity derivative instruments.

Summarized Derivative Information

The following summarizes the balance within AOCI relative to our commodity and interest rate cash flow hedges:


	June 30, 2009
	(Millions)
Interest rate cash flow hedges:

Net deferred losses in AOCI	$	(0.6	)

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked to market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized as follows:


Balance Sheet Line Item	June 30, 2009		Balance Sheet Line Item	June 30, 2009
	(Millions)			(Millions)
Derivative Assets Designated as Hedging Instruments:			Derivative Liabilities Designated as Hedging Instruments:
Interest rate derivatives:			Interest rate derivatives:
Unrealized gains on derivative instruments – current	$	—	Unrealized losses on derivative instruments – current	$	(18.7	)
Unrealized gains on derivative instruments – long term		0.9	Unrealized losses on derivative instruments – long term		(12.8	)

	$	0.9		$	(31.5	)

Derivative Assets Not Designated as Hedging Instruments:			Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:			Commodity derivatives:
Unrealized gains on derivative instruments – current	$	5.9	Unrealized losses on derivative instruments – current	$	(7.0	)
Unrealized gains on derivative instruments – long term		2.9	Unrealized losses on derivative instruments – long term		(30.8	)

	$	8.8		$	(37.8	)

The following table summarizes the impact on our condensed consolidated balance sheet and earnings of our derivative instruments that are accounted for using the cash flow hedge method of accounting.


	Deferred Losses in AOCI Expected to be Reclassified into Earnings Over the Next 12 Months
	(Millions)
Interest rate derivatives	$	(0.4	)
Commodity derivatives	$	—

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

The following table represents, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below.


	June 30, 2009
	Crude Oil		Natural Gas		Natural Gas Liquids
Year of Expiration	Net Long (Short) Position (Bbls)		Net Long (Short) position (MMbtu)		Net Long (Short) Position (Bbls)
2009	(450,800	)	(1,350,000	)	(111,621	)
2010	(950,225	)	(2,023,500	)	(74,001	)
2011	(949,000	)	(1,314,000	)	—
2012	(777,750	)	(1,317,600	)	—
2013	(748,250	)	(730,000	)	—
2014	(365,000	)	—		—

We periodically enter into interest rate swap agreements to mitigate our floating rate interest exposure. As of June 30, 2009 we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange $575.0 million of our floating rate obligation to a fixed rate obligation.

11.

Non-Controlling Interest

Non-controlling interest represents (1) the ownership interests of DCP Partners’ public unitholders in net assets of DCP Partners through DCP Partners’ publicly traded common units; (2) affiliate ownership interests in common units and Class D units; (3) the non-controlling interest holders’ portion of the net assets of our Collbran Valley Gas Gathering system joint venture, acquired with the MEG acquisition in August 2007; (4) the non-controlling interest holders’ portion of the net assets of Jackson Pipeline Company, a partnership we acquired with the MPP acquisition in October 2008; and (5) the noncontrolling interest holders’ portion in the net assets of East Texas.

We own approximately a 1% general partner interest and a 1% limited 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 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, 2009, DCP Partners had outstanding 28,233,183 common units and 3,500,000 Class D 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 2009, DCP Partners issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP LP Holdings, LP and DCP Midstream GP, LP in consideration for an additional 25.1% interest in East Texas and the NGL Hedge. The Class D units represent limited partnership interests in the partnership.

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 us as 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 us as the general partner for any one or more of the next four quarters;

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

•

plus, if we, as the general partner so determine, 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 2007, as the general partner, we were entitled to 2% of all quarterly distributions that we make prior to DCP Partners’ liquidation. We have the right, but not the obligation, to contribute a proportionate amount of capital to maintain our current general partner interest. We did not participate in certain issuances of common units by DCP Partners during 2007 and 2008. Therefore, our 2% interest in these distributions was reduced to approximately 1%.

The incentive distribution rights held by us as the general partner entitle us to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution related to our incentive distribution rights is at the highest level. Our incentive distribution rights were not reduced as a result of these private placement agreements, 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 DCP Partners to maintain our current general partner interest. Please read the Distributions of Available Cash after the Subordination Period section below for more details about the distribution targets and their impact on our incentive distribution rights.

Class D Units — The Class D Units will be eligible to receive distributions of Available Cash in August 2009, including the payment of the second quarter distribution. The Class D Units otherwise generally have the same rights as the Partnership’s outstanding Common Units and will convert into the Partnership’s Common Units on a one-for-one basis on August 17, 2009.

Subordinated Units — All of the subordinated units were held by DCP Midstream, LLC. The subordination period had an early termination provision that permitted 50% of the subordinated units, or 3,571,428 units, to convert into common units on a one-to-one basis in February 2008 and permitted the other 50% of the subordinated units, or 3,571,429 units, to convert into common units on a one-to-one basis in February 2009, following the satisfactory completion of the tests for ending the subordination period contained in the partnership agreement. DCP Partners’ board of directors certified that all conditions for early conversion were satisfied.

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, which ended in February 2009, in the following manner:

•

first, to all unitholders and us as the general partner, in accordance with their pro rata interest, 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 DCP Partners’ cash distributions paid in 2009:


Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
May 15, 2009	$	0.600	$	20.1
February 13, 2009		0.600		20.1

12.

Partners’ Equity

At June 30, 2009, partners’ equity consisted of our capital account, AOCI and a note receivable from DCP Midstream, LLC.

As of June 30, 2009, we had a balance of $0.3 million in our partners’ equity account.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

13.

Commitments and Contingent Liabilities

Litigation — We are a party to various legal proceedings, as well as 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 these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our condensed consolidated financial position.

Anderson Gulch — In February 2009, the Colorado Department of Public Health and Environment, or CDPHE, issued a Notice of Violation that alleges violations of the environmental permit at our Anderson Gulch gas plant in 2008. The Anderson Gulch gas plant is owned by Collbran Valley Gas Gathering, LLC, our 70% owned joint venture in western Colorado. We have negotiated a resolution of this matter with the CDPHE for approximately $186,000, which will consist of a monetary penalty and an agreement to perform a supplemental environmental project.

El Paso — On February 27, 2009, a jury in the District Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, L.P., or El Paso, and against one of our subsidiaries and DCP Midstream, LLC. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which includes periods of time prior to our ownership of this asset. Our responsibility for this judgment will be limited to the time period after we acquired the asset from DCP Midstream, LLC in December 2005. During the second quarter of 2009 we filed an appeal in the 14^th Court of Appeals, Texas and will continue to defend ourselves vigorously against this claim. El Paso has filed an additional lawsuit in Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the asset. We intend to file motions to remove us from the Louisiana matter. As a result of the jury verdict, we recorded a contingent liability of $2.5 million in the fourth quarter of 2008 for this matter, which is included in other long-term liabilities in the condensed consolidated balance sheet as of June 30, 2009.

Indemnification — DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors.

Insurance — We renewed our insurance policies in June and July 2009 for the 2009-2010 insurance year. Previously, we carried insurance jointly with DCP Midstream, LLC. Following our 2009 renewals, we now contract with a third party insurer separately from DCP Midstream for: (1) statutory workers’ compensation insurance; (2) automobile liability insurance for all owned, non-owned and hired vehicles; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of all real and personal property and includes business interruption/extra expense. However, we are still jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. As a result of separating this insurance, we have reduced the excess liability and property limits to match the type and size of assets covered by this insurance. These changes have not resulted in any material change to the premiums we will pay in the 2009-2010 insurance year. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies that are of similar size to us and with similar types of operations.

Discovery’s previous property insurance policy expired in June 2009. Our insurance on Discovery for the 2009-2010 insurance year covers onshore and offshore property, onshore named windstorm and onshore business interruption insurance. The availability of named windstorm insurance has been significantly reduced as a result of higher industry-wide damage claims in past years. Additionally, the named windstorm insurance that is available comes at significantly higher premium amounts, higher deductibles and lower coverage limits. Consequently, Discovery elected to not purchase offshore named windstorm insurance coverage for the 2009-2010 insurance year.

14.

Business Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.

DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET — (Continued)

AS OF JUNE 30, 2009

Natural Gas Services — The Natural Gas Services segment consists of (1) the Northern Louisiana system; (2) the Southern Oklahoma system; (3) our 40% limited liability company interest in Discovery; (4) our Colorado and Wyoming systems; (5) our East Texas system; and (6) our Michigan systems (acquired in October 2008).

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of five owned and operated rail terminals, one leased marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, and a non-operated 45% equity interest in the Black Lake interstate NGL pipeline.

These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations.

The following table sets forth our segment information:


	June 30, 2009
	(Millions)
Segment long-term assets:
Natural Gas Services	$	1,141.9
Wholesale Propane Logistics		54.0
NGL Logistics		33.3
Other (a)		40.3

Total long-term assets		1,269.5
Current assets		121.9

Total assets	$	1,391.4

(a)	Other long-term assets not allocable to segments consist of restricted investments, unrealized gains on derivative instruments, and other long-term assets.

15.

Subsequent Events

We have evaluated subsequent events occurring through August 10, 2009, the date the financial statements were issued.

On July 28, 2009, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on August 14, 2009 to unitholders of record on August 7, 2009.