Exhibit 99.1

DCP Midstream GP, LP

(A Delaware Limited Partnership)

Unaudited Condensed Consolidated Balance Sheet

As of June 30, 2008

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET OF

DCP MIDSTREAM GP, LP

TABLE OF CONTENTS

	Page
Unaudited Condensed Consolidated Balance Sheet as of June 30, 2008	2
Notes to Unaudited Condensed Consolidated Balance Sheet	3

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DCP MIDSTREAM GP, LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

	June 30, 2008
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	12.3
Short-term investments		1.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.5 million		56.0
Affiliates		77.0
Inventories		39.3
Unrealized gains on derivative instruments		1.4
Other		39.2
Total current assets		226.3
Restricted investments		221.1
Property, plant and equipment, net		498.8
Goodwill		82.1
Intangible assets, net		28.8
Equity method investments		184.7
Unrealized gains on derivative instruments		2.8
Other long-term assets		1.1
Total assets	$	1,245.7
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable:
Trade	$	94.6
Affiliates		37.4
Unrealized losses on derivative instruments		78.5
Accrued interest payable		0.8
Other		16.9
Total current liabilities		228.2
Long-term debt		660.0
Unrealized losses on derivative instruments		218.1
Other long-term liabilities		14.3
Total liabilities		1,120.6
Non-controlling interests		133.4
Commitments and contingent liabilities
Partners’ deficit:
Partners’ equity		174.9
Note receivable from DCP Midstream, LLC		(183.0	)
Accumulated other comprehensive loss		(0.2	)
Total partners’ deficit		(8.3	)
Total liabilities and partners’ deficit	$	1,245.7

See accompanying notes to unaudited condensed consolidated balance sheet.

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DCP MIDSTREAM GP, LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2008

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 a 1.3% interest in and act as the general partner for DCP Midstream Partners, LP, or DCP Partners or the partnership, a master limited partnership, 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 (acquired in May 2007); our limited liability company interests in DCP East Texas Holdings, LLC, or East Texas, and Discovery Producer Services LLC, or Discovery (acquired in July 2007); our Wyoming system and a 70% interest in our Colorado system (each acquired in August 2007); our wholesale propane logistics business; and our NGL transportation pipelines.

The condensed consolidated balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The 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 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 condensed 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 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, 2007 included as Exhibit 99.1 to DCP Partners’ Form 10-K filed with the Securities and Exchange Commission, or SEC, on March 10, 2008.

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 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.

Fair Value Measurements — We measure our derivative financial assets and liabilities related to our commodity derivative activity and our interest rate swaps at fair value as of each balance sheet date. While we utilize as much information as is readily observable in the marketplace in determining fair value, to the extent that information is not available we may use a combination of indirectly observable facts or, in certain instances, may develop our own expectation of the fair value. Calculating the fair value of an instrument is a highly subjective process and involves a significant level of judgment based on our interpretation of a variety of market conditions. The resulting fair value may be significantly different from one measurement date to the next. All realized and unrealized gains and losses, and settlements of commodity derivative instruments are recorded in earnings. All unrealized gains and losses resulting from changes in the fair value of our interest rates swaps are recorded in the condensed consolidated balance sheet within accumulated other comprehensive income, or AOCI.

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 $5.4 million of gain on sale of common units in DCP Partners, which is included in other long-term liabilities in the condensed consolidated balance sheet. This gain is related to DCP Partners’ equity issuances in June 2007, August 2007 and March 2008. We will recognize this gain in earnings upon conversion of all of DCP Partners’ subordinated units to common units.

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3. Recent Accounting Pronouncements

Statement of Financial Accounting Standards, or SFAS, No. 162 “The Hierarchy of Generally Accepted Accounting Principles,” or SFAS 162 — In May 2008, the Financial Accounting Standards Board, or FASB, issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. SFAS 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS 162 to have a significant impact on our consolidated financial position.

FASB Staff Position, or 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 a recognized intangible. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We are in the process of assessing the impact of FSP 142-3 on our consolidated financial position.

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. SFAS 161 is effective for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our disclosures.

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. SFAS 160 is effective for us on January 1, 2009. We are in the process of assessing the impact of SFAS 160 on our financial position.

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 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. SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively upon adoption, we will account for all transactions with closing dates subsequent to the adoption date in accordance with the provisions of the standard.

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 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. The provisions of SFAS 159 were effective for us on January 1, 2008. We have not elected the fair value option relative to any of our financial assets and liabilities which are not otherwise required to be measured at fair value by other accounting standards. Therefore, there is no effect of adoption reflected in our consolidated financial position.

SFAS No. 157, “Fair Value Measurements,” or SFAS 157 — In September 2006, the FASB issued SFAS 157, which was effective for us on January 1, 2008. SFAS 157:

• defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date;

• establishes a framework for measuring fair value;

• establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date;

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• nullifies the guidance in Emerging Issues Task Force, or EITF, 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique; and

• significantly expands the disclosure requirements around instruments measured at fair value.

Upon the adoption of this standard we incorporated the marketplace participant view as prescribed by SFAS 157. Such changes included, but were not limited to, changes in valuation policies to reflect an exit price methodology, the effect of considering our own non-performance risk on the valuation of liabilities, and the effect of any change in our credit rating or standing. As a result of adopting SFAS 157, we recorded a cumulative effect transition adjustment of approximately $5.8 million as an increase to earnings and an insignificant amount as an increase to AOCI during the three months ended March 31, 2008. All changes in our valuation methodology have been incorporated into our fair value calculations as of June 30, 2008.

Pursuant to FASB Staff Position 157-2, the FASB issued a partial deferral, ending on December 31, 2008, of the implementation of SFAS 157 as it relates to all non-financial assets and liabilities where fair value is the required measurement attribute by other accounting standards. While we have adopted SFAS 157 for all financial assets and liabilities effective January 1, 2008, we have not assessed the impact that the adoption of SFAS 157 will have on our non-financial assets and liabilities.

FSP of Financial Interpretation, or FIN, 39-1, “Amendment of FASB Interpretation No. 39,” or FSP FIN 39-1 — In April 2008, the FASB issued FSP FIN 39-1, which permits, but does not require, a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP FIN 39-1 became effective for us beginning on January 1, 2008, however, we have elected to continue our policy to not offset cash collateral against our derivative asset or liability positions, and will continue to reflect such amounts on a gross basis in our condensed consolidated balance sheet.

4. Acquisitions

Gathering and Compression Assets

In August 2007, we acquired certain subsidiaries of Momentum Energy Group, Inc., or MEG, from DCP Midstream, LLC for approximately $165.8 million. As a result of the acquisition, we expanded our operations into the Piceance and Powder River producing basins, thus diversifying our business into new operating areas. The consideration 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 totaling $10.9 million for net working capital and general and administrative charges. We financed this transaction with $120.0 million of borrowings under our credit agreement, along with the issuance of common units through a private placement with certain institutional investors and cash on hand. In August 2007, we issued 2,380,952 common limited partner 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 $100.0 million in the aggregate. The proceeds from this private placement were used to purchase high-grade securities to fully secure our term loan borrowings. These units were registered with the SEC in January 2008.

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The transfer of the MEG subsidiaries between DCP Midstream, LLC and us represents a transfer between entities under common control. Transfers between entities under common control are accounted for at DCP Midstream, LLC’s carrying value, similar to the pooling method. DCP Midstream, LLC recorded its acquisition of the MEG subsidiaries under the purchase method of accounting, whereby the assets and liabilities were recorded at their respective fair values as of the date of the acquisition, and we recorded goodwill of approximately $52.8 million, including purchase price adjustments of $1.9 million during the first quarter of 2008. The goodwill amount recognized relates primarily to projected growth in the Piceance basin due to significant natural gas reserves and high levels of drilling activity. The purchase price allocation is as follows:

	(Millions)
Cash consideration	$	153.8
Payable to DCP Midstream, LLC		10.9
Common limited partner units		12.0
Aggregate consideration	$	176.7
Cash	$	11.8
Accounts receivable		14.1
Other assets		1.5
Property, plant and equipment		127.8
Goodwill		52.8
Intangible assets		15.5
Accounts payable		(11.1	)
Other liabilities		(12.9	)
Non-controlling interest in joint venture		(22.8	)
Total purchase price allocation	$	176.7

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 provided parental guarantees, totaling $63.0 million at June 30, 2008, to certain counterparties to our commodity derivative instruments.

Other Agreements and Transactions with DCP Midstream, LLC

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 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.

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 has made capital contributions of $1.6 million to DCP Partners during the six months ended June 30, 2008 as reimbursement for these capital projects.

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, 2008. All interest income earned under the note has been distributed to DCP Midstream, LLC.

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In accordance with our partnership agreement, we distribute all available cash to our partners according to their respective ownership interest.

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 the second quarter of 2008, we entered into a propane supply agreement with Spectra Energy. The propane supply agreement, effective May 1, 2008 and terminating April 30, 2014, provides us propane supply at our marine terminal, for up to approximately 120 million gallons of propane annually. This contract replaces the supply that was previously provided under a contract with a third party that was terminated during the first quarter of 2008.

ConocoPhillips

We have multiple agreements whereby we provide a variety of services for ConocoPhillips and its affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing arrangements, 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 $1.3 million of capital reimbursements during the six months ended June 30, 2008.

Summary of Transactions with Affiliates

We had accounts receivable and accounts payable with affiliates as follows:

	June 30, 2008
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	72.6
Accounts payable	$	29.2
Spectra Energy:
Accounts receivable	$	0.8
Accounts payable	$	0.3
ConocoPhillips:
Accounts receivable	$	3.6
Accounts payable	$	7.9

6. 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.

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• 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 an inactive (or less active) market 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 the notional contract volume.

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. See Note 10 Risk Management and Hedging Activities.

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 lowest level of input that is significant to the fair value measurement. 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 OTC natural gas contracts, crude oil or NGL contracts.

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 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.

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

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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 correlation 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 from a higher level within the hierarchy to a lower level 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, and are held with major financial institutions, which are expected to fully perform under the terms of our agreements. The swaps are generally priced based upon a United States Treasury instrument with similar duration, adjusted by the credit spread between our company and the United States Treasury 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, our entity valuation, as well as liquidity reserves 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, money market instruments and highly rated tax-exempt debt securities that have stated maturities of 20 years or less, which are categorized as available-for-sale securities. 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 and highly rated tax-exempt debt securities are priced using a yield curve for similarly rated instruments, and are classified within Level 2.

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The following table presents the financial instruments carried at fair value as of June 30, 2008, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:

	Total Carrying Value			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)
	(Millions)
Current assets:
Short-term investments	$	1.1		$	—	$	1.1		$	—
Commodity derivative instruments (a)	$	1.4		$	—	$	0.4		$	1.0
Long-term assets:
Restricted investments	$	221.1		$	—	$	221.1		$	—
Commodity derivative instruments (b)	$	1.6		$	—	$	—		$	1.6
Interest rate instruments (b)	$	1.2		$	—	$	1.2		$	—
Current liabilities (c):
Commodity derivative instruments	$	(71.2	)	$	—	$	(63.7	)	$	(7.5	)
Interest rate instruments	$	(7.3	)	$	—	$	(7.3	)	$	—
Long-term liabilities (d):
Commodity derivative instruments	$	(212.9	)	$	—	$	(205.2	)	$	(7.7	)
Interest rate instruments	$	(5.2	)	$	—	$	(5.2	)	$	—

(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.

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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.

	Balance at December 31, 2007			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, 2008
	(Millions)
Commodity derivative instruments:
Current assets	$	0.2		$	1.0		$	—		$	(0.2	)	$	1.0
Long-term assets	$	1.5		$	0.1		$	—		$	—		$	1.6
Current liabilities	$	(1.6	)	$	(2.7	)	$	(5.0	)	$	1.8		$	(7.5	)
Long-term liabilities	$	(0.2	)	$	(2.9	)	$	(4.6	)	$	—		$	(7.7	)

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

7. Debt

Long-term debt was as follows:

	June 30, 2008
	(Millions)
Revolving credit facility, weighted-average interest rate of 3.19%, due June 21, 2012 (a)	$	440.0
Term loan facility, interest rate of 2.59%, due June 21, 2012		220.0
Total long-term debt	$	660.0

(a) $425.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 3.97% to 5.19%, for a net effective rate of 5.16% on the $440.0 million of outstanding debt under our revolving credit facility as of June 30, 2008.

Credit Agreement

We have a 5-year credit agreement, or the Credit Agreement, consisting of a $630.0 million revolving credit facility and a $220.0 million term loan facility. 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 sheet as of June 30, 2008. The unused portion of the revolving credit facility may be used for general corporate purposes and letters of credit. At June 30, 2008, we had $0.3 million of letters of credit outstanding under the Credit Agreement. As of June 30, 2008, the available capacity under our revolving credit facility was $189.7 million.

Other Agreements

As of June 30, 2008, we had outstanding letters of credit with counterparties to our commodity derivative instruments of $75.0 million, which reduce the amount of cash we may be required to post as collateral. These letters of credit were issued directly by financial institutions and do not reduce the available capacity under our credit facility.

8. 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 in all of the subordinated units; and (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.

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We own a 1.3% 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 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, 2008, DCP Partners had outstanding 24,661,754 common units and 3,571,429 subordinated 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 March 2008, DCP Partners issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.1 million, net of offering costs.

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;

• 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. Therefore, our 2% interest in these distributions was reduced to 1.3%.

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. 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 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.

Subordinated Units — All of the subordinated units are held by DCP Midstream, LLC. DCP Partners’ 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. DCP Partners determined that the criteria set forth in the partnership agreement for early termination of the subordination period occurred in February 2008 and, therefore, 50% of the subordinated units converted into common units. DCP Partners’ board of directors and the conflicts committee of the board certified that all conditions for early conversion were 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.

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Distributions of Available Cash during the Subordination Period — DCP Partners’ partnership agreement, after adjustment for our relative ownership level, currently 1.3%, 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 their pro rata interest, 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 their pro rata interest, 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 their 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 their 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 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 2008:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
May 15, 2008	$	0.590	$	19.6
February 14, 2008		0.570		15.7

Our current distribution places us in the Fourth Target Distribution level.

9. Partners’ Deficit

At June 30, 2008, partners’ deficit consisted of our capital account, AOCI and a note receivable from DCP Midstream, LLC.

As of June 30, 2008, we had a deficit balance of $8.3 million in our partners’ 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 partners’ 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 partners’ deficit account.

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10. Risk Management and Hedging Activities

The impact of our derivative activity on our financial position is summarized below:

	June 30, 2008
	(Millions)
Interest rate cash flow hedges:
Net deferred losses in AOCI	$	(0.2	)

For the six months ended June 30, 2008, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

As of June 30, 2008, we had outstanding letters of credit with counterparties to our commodity derivative instruments of $75.0 million. These letters of credit reduce the amount of cash we may be required to post as collateral. As of June 30, 2008, we had cash collateral posted with certain counterparties to our commodity derivative instruments of approximately $39.1 million, which is included in other current assets on the condensed consolidated balance sheet.

Commodity Cash Flow Protection Activities — We use NGL, natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. We use the mark-to-market method of accounting for all commodity derivative instruments. As a result, an insignificant amount of the remaining net loss deferred in AOCI at June 30, 2008 is expected to be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings. The changes in fair value of financial derivatives are included in earnings. The agreements are with major financial institutions, which management expects to fully perform under the terms of the agreements.

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. We may hedge producer price locks (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 (New York Mercantile Exchange or index-based).

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 $425.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation. 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 sheet. Deferred net losses of $0.1 million 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. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 3.97% to 5.19%, and receive interest payments based on the three-month London Interbank Offered Rate, or 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. 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 consolidated financial position. See Note 16 in Exhibit 99.1 of DCP Partners’ 2007 Form 10-K for additional details.

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 predecessor operations. See the “Indemnification” section of Note 5 in Exhibit 99.1 of DCP Partners’ 2007 Form 10-K for additional details.

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12. Subsequent Events

During the second quarter of 2008, we announced that DCP Midstream, LLC plans to offer to sell its 75% interest in East Texas to us. The closing of this transaction may be deferred beyond our original 2008 target date.

On July 24, 2008, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on August 14, 2008 to unitholders of record on August 7, 2008. This distribution of $0.60 per unit places us in the Fourth Target Distribution level (see Note 8 for discussion of distributions of available cash).

In July 2008, we received a distribution of $8.8 million from Discovery for the second quarter of 2008.

In July 2008, DCP Midstream issued parental guarantees totaling $200.0 million to certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream a fee of 0.5% per annum on these outstanding guarantees.

During the third quarter of 2008, we announced plans to invest, along with the partners to our joint venture, approximately $150.0 million over a multi-year period to construct a gathering pipeline to support our Colorado system, located in the Collbran Valley area of the Piceance Basin in western Colorado. Our interest in this pipeline is 70%.

During the third quarter of 2008, we announced plans, along with DCP Midstream, LLC, to invest approximately $56.0 million in East Texas to construct a gathering pipeline to support the East Texas system. Our interest in this pipeline is 25%.

During the third quarter of 2008, we announced plans, along with M2 Midstream, LLC, an unaffiliated entity, to pursue development of a natural gas pipeline in northern Louisiana.

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