Edgar Filing: DCP Midstream Partners, LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-32678

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware		03-0567133
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

370 17th Street, Suite 2775 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

As of May 2, 2008, there were outstanding 24,661,754 common limited partner units and 3,571,429 subordinated units.

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2008

TABLE OF CONTENTS


Item		Page
	PART I. FINANCIAL INFORMATION

1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2008 and 2007	2
	Condensed Consolidated Statements of Comprehensive (Loss) Income for the Three Months Ended March 31, 2008 and 2007	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	4
	Notes to the Condensed Consolidated Financial Statements	5
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
3.	Quantitative and Qualitative Disclosures about Market Risk	41
4.	Controls and Procedures	43

	PART II. OTHER INFORMATION

1.	Legal Proceedings	44
1A.	Risk Factors	44
6.	Exhibits	45

	Signatures	46
	Exhibit Index	47

	Certification of Chief Executive Officer Pursuant to Section 302
	Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) Pursuant to Section 302
	Certification of Chief Executive Officer Pursuant to Section 906
	Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) Pursuant to Section 906

GLOSSARY OF TERMS

The following is a list of certain industry terms used throughout this report:


Bbls		barrels
Bbls/d		barrels per day
Btu		British thermal unit, a measurement of energy
Frac spread		price differences, measured in energy units, between equivalent amounts of natural gas and natural gas liquids
Fractionation		the process by which natural gas liquids are separated into individual components
MBbls		one thousand barrels
MBbls/d		one thousand barrels per day
MMBtu		one million British thermal units, a measurement of energy
MMBtu/d		one million British thermal units per day, a measurement of energy
MMcf		one million cubic feet
MMcf/d		one million cubic feet per day
NGLs		natural gas liquids
Throughput		the volume of product transported or passing through a pipeline or other facility

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2007, as well as the following risks and uncertainties:

•

the level and success of natural gas drilling around our assets, and our ability to connect supplies to our gathering and processing systems in light of competition;

•

our ability to grow through acquisitions, contributions from affiliates, or organic growth projects, and the successful integration and future performance of such assets;

•

our ability to access the debt and equity markets, which will depend on general market conditions, interest rates and our ability to effectively limit a portion of the adverse effects of potential changes in interest rates by entering into derivative financial instruments, and the credit ratings for our debt obligations;

•

the extent of changes in commodity prices, our ability to effectively limit a portion of the adverse impact of potential changes in prices through derivative financial instruments, and the potential impact of price on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

•

our ability to purchase propane from our principal suppliers for our wholesale propane logistics business;

•

our ability to construct facilities in a timely fashion, which is partially dependent on obtaining required building, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for supplies;

•

the creditworthiness of counterparties to our transactions;

•

weather and other natural phenomena, including their potential impact on demand for the commodities we sell and our third-party-owned infrastructure;

•

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of our industry;

•

industry changes, including the impact of consolidations, increased delivery of liquefied natural gas to the United States, alternative energy sources, technological advances and changes in competition;

•

the amount of collateral we may be required to post from time to time in our transactions; and

•

general economic, market and business conditions.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

iii

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2008			December 31, 2007
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	53.1		$	24.5
Short-term investments		0.4			1.3
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1.0 million and $1.2 million, respectively		62.0			81.7
Affiliates		50.3			52.1
Inventories		31.0			37.3
Unrealized gains on derivative instruments		0.6			3.1
Other		7.8			18.5

Total current assets		205.2			218.5
Restricted investments		220.4			100.5
Property, plant and equipment, net		503.9			500.7
Goodwill		82.1			80.2
Intangible assets, net		29.2			29.7
Equity method investments		188.1			187.2
Unrealized gains on derivative instruments		2.4			2.7
Other long-term assets		1.2			1.2

Total assets	$	1,232.5		$	1,120.7

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	74.9		$	110.2
Affiliates		38.1			55.6
Unrealized losses on derivative instruments		41.1			30.9
Accrued interest payable		1.0			1.6
Other		18.2			21.3

Total current liabilities		173.3			219.6
Long-term debt		655.0			630.0
Unrealized losses on derivative instruments		98.9			70.0
Other long-term liabilities		8.7			5.8

Total liabilities		935.9			925.4

Non-controlling interests		29.6			26.9
Commitments and contingent liabilities
Partners’ equity:
Common unitholders (24,661,754 and 16,840,326 units issued and outstanding, respectively)		364.5			308.8
Subordinated unitholders (3,571,429 and 7,142,857 convertible units issued and outstanding, respectively)		(63.6	)		(120.1	)
General partner interest		(5.7	)		(5.4	)
Accumulated other comprehensive loss		(28.2	)		(14.9	)

Total partners’ equity		267.0			168.4

Total liabilities and partners’ equity	$	1,232.5		$	1,120.7

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31,
	2008			2007
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	251.8		$	178.3
Sales of natural gas, propane, NGLs and condensate to affiliates		110.9			54.6
Transportation, processing and other		5.8			3.3
Transportation, processing and other to affiliates		6.3			4.0
Losses from commodity derivative activity, net		(37.8	)		(2.9	)
Gains (losses) from commodity derivative activity, net — affiliates		0.7			(0.1	)

Total operating revenues		337.7			237.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		247.9			163.1
Purchases of natural gas, propane and NGLs from affiliates		81.8			47.8
Operating and maintenance expense		10.6			6.6
Depreciation and amortization expense		8.5			3.4
General and administrative expense		2.6			2.5
General and administrative expense — affiliates		2.9			2.3

Total operating costs and expenses		354.3			225.7

Operating (loss) income		(16.6	)		11.5
Interest income		1.6			1.7
Interest expense		(8.1	)		(3.8	)
Earnings from equity method investments		17.2			6.4
Non-controlling interest in income		(0.6	)		—

Net (loss) income	$	(6.5	)	$	15.8
Less:
Net income attributable to predecessor operations		—			(3.3	)
General partner interest in net income		(1.7	)		(0.3	)

Net (loss) income allocable to limited partners	$	(8.2	)	$	12.2

Net (loss) income per limited partner unit — basic and diluted	$	(0.33	)	$	0.58

Weighted-average limited partner units outstanding — basic and diluted		24.9			17.7

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)


	Three Months Ended March 31,
	2008			2007
	(Millions)
Net (loss) income	$	(6.5	)	$	15.8

Other comprehensive loss:
Reclassification of cash flow hedges into earnings		0.4			(1.4	)
Net unrealized losses on cash flow hedges		(13.7	)		(5.3	)

Total other comprehensive loss		(13.3	)		(6.7	)

Total comprehensive (loss) income	$	(19.8	)	$	9.1

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2008			2007
	(Millions)
OPERATING ACTIVITIES:
Net (loss) income	$	(6.5	)	$	15.8
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization expense		8.5			3.4
Earnings from equity method investments, net of distributions		2.0			(0.8	)
Non-controlling interest in income		0.6			—
Other, net		(0.5	)		(0.5	)
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable		21.3			10.8
Inventories		6.2			0.2
Net unrealized losses on derivative instruments		28.6			3.0
Accounts payable		(43.3	)		(10.2	)
Accrued interest		(0.6	)		(0.3	)
Other current assets and liabilities		8.9			(1.8	)
Other long-term assets and liabilities		(0.1	)		0.2

Net cash provided by operating activities		25.1			19.8

INVESTING ACTIVITIES:
Capital expenditures		(9.2	)		(3.4	)
Acquisition of subsidiaries of Momentum Energy Group, Inc.		(10.9	)		—
Investments in equity method investments		(2.8	)		(2.4	)
Payment of earnest deposit		—			(9.0	)
Purchases of available-for-sale securities		(389.0	)		(5,661.3	)
Proceeds from sales of available-for-sale securities		270.3			5,660.4

Net cash used in investing activities		(141.6	)		(15.7	)

FINANCING ACTIVITIES:
Borrowings of debt		255.0			—
Repayments of debt		(230.0	)		—
Proceeds from issuance of common units, net of offering costs		132.3			—
Purchase of units		—			(0.2	)
Excess purchase price over acquired assets		—			(9.9	)
Net change in advances from DCP Midstream, LLC		—			(3.2	)
Distributions to unitholders		(16.2	)		(7.8	)
Contributions from non-controlling interests		2.1			—
Contributions from DCP Midstream, LLC		1.9			0.2

Net cash provided by (used in) financing activities		145.1			(20.9	)

Net change in cash and cash equivalents		28.6			(16.8	)
Cash and cash equivalents, beginning of period		24.5			46.2

Cash and cash equivalents, end of period	$	53.1		$	29.4

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Description of Business and Basis of Presentation

DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we or our, 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 NGLs and condensate.

We are a Delaware master limited partnership. Our 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.

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to us and operate our assets. DCP Midstream, LLC owns approximately 30% of our partnership.

The acquisition from DCP Midstream, LLC in July 2007 of our limited liability company interest in East Texas and Discovery, and a non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, was a transaction among entities under common control. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, prior periods are retroactively adjusted to furnish comparative information similar to the pooling method and the amount of the purchase price in excess of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to partners’ equity. Accordingly, our financial information includes the historical results of East Texas, Discovery and the Swap for all periods presented. In addition, the results of operations of Momentum Energy Group Inc., or MEG, have been included in the condensed consolidated financial statements since the date of acquisition in August 2007.

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. We refer to the equity interests in East Texas and Discovery, and the Swap, for periods prior to our acquisition, collectively as our “predecessor.” The condensed consolidated financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. All significant intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been identified in the condensed consolidated financial statements as transactions between affiliates.

The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, these condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and notes normally included in our annual financial statements have been condensed or omitted from these interim financial statements pursuant to such rules and regulations. These condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and notes thereto included in our 2007 Form

10-K.

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 financial statements 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

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 the condensed consolidated statements of operations as losses from commodity derivative activity, net. All unrealized gains and losses resulting from changes in the fair value of our interest rates swaps are recorded in the condensed consolidated balance sheets within accumulated other comprehensive income, or AOCI.

3.	Recent Accounting Pronouncements

Statement of Financial Accounting Standards, or SFAS, No. 161 “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133,” or SFAS 161 — In March 2008, the Financial Accounting Standards Board, or 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 have not assessed the impact of SFAS 161 on our consolidated results of operations, cash flows or financial position.

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. The Statement 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 have not assessed the impact of SFAS 160 on our consolidated results of operations, cash flows or 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 results of operations, cash flows or financial position.

SFAS No. 157, “Fair Value Measurements,” or SFAS 157 — In September 2006, the FASB issued SFAS 157, which is 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;

•

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

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

•

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 have recorded a cumulative effect transition adjustment of approximately $5.8 million as an increase to earnings and approximately $1.3 million as an increase to AOCI during the three months ended March 31, 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.

FASB Staff Position of Financial Interpretation 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. This FSP 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 sheets.

4.	Acquisitions

Gathering and Compression Assets

In August 2007, we acquired certain subsidiaries of 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.

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, including goodwill of approximately $52.8 million. 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:

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	(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

In May 2007, we acquired certain gathering and compression assets located in southern Oklahoma, or the Southern Oklahoma system, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181.1 million.

In April 2007, we acquired certain gathering and compression assets located in northern Louisiana from Laser Gathering Company, LP for approximately $10.2 million.

The results of operations for the MEG subsidiaries, and the Oklahoma and Louisiana acquired assets, have been included prospectively, from the dates of acquisition, as part of the Natural Gas Services segment.

On July 1, 2007, we acquired a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery and the Swap from DCP Midstream, LLC, for aggregate consideration of approximately $271.3 million, consisting of approximately $243.7 million in cash, including net working capital of $1.3 million and other adjustments, the issuance of 620,404 common units to DCP Midstream, LLC valued at $27.0 million and the issuance of 12,661 general partner equivalent units valued at $0.6 million. We financed the cash portion of this transaction with borrowings of $245.9 million under our amended credit facility. The $118.0 million excess purchase price over the historical basis of the net acquired assets was recorded as a reduction to partners’ equity, and the $27.6 million of common and general partner equivalent units issued as partial consideration for this transaction was recorded as an increase to partners’ equity. The following tables present the impact on the condensed consolidated statements of operations, adjusted for the acquisition of East Texas, Discovery and the Swap, from DCP Midstream, LLC, for the three months ended March 31, 2007:

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	DCP Midstream Partners, LP			East Texas, Discovery and the Swap			Combined DCP Midstream Partners, LP
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	232.9		$	—		$	232.9
Transportation and other		7.2			(2.9	)		4.3

Total operating revenues		240.1			(2.9	)		237.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		210.9			—			210.9
Operating and maintenance expense		6.6			—			6.6
Depreciation and amortization expense		3.4			—			3.4
General and administrative expense		4.8			—			4.8

Total operating costs and expenses		225.7			—			225.7

Operating income (loss)		14.4			(2.9	)		11.5
Interest expense, net		(2.1	)		—			(2.1	)
Earnings from equity method investments		0.2			6.2			6.4

Net income	$	12.5		$	3.3		$	15.8

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. During the three months ended March 31, 2008 and 2007, we incurred fees of $2.4 million and $1.7 million, respectively, under the Omnibus Agreement and other fees paid to DCP Midstream, LLC of $0.5 million and $0.6 million, respectively.

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 to, 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 was a significant customer during the three months ended March 31, 2008 and 2007.

In conjunction with our acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for certain Discovery capital projects, which were forecasted to be completed prior to our acquisition of a 40% limited liability company interest in Discovery. DCP Midstream, LLC has made capital contributions of $1.6 million to us during the three months ended March 31, 2008 to reimburse us for these capital projects.

ConocoPhillips

We have multiple agreements whereby we provide a variety of services to ConocoPhillips and its affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing arrangements, 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 $0.9 million and $1.2 million of capital reimbursements during the three months ended March 31, 2008 and 2007, respectively.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:


	Three Months Ended March 31,
	2008		2007
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	110.1	$	54.6
Transportation, processing and other	$	5.5	$	1.6
Purchases of natural gas, propane and NGLs	$	75.2	$	40.0
Gains (losses) from commodity derivative activity, net	$	0.7	$	(0.1	)
General and administrative expense	$	2.9	$	2.3
Spectra Energy:
Sales of natural gas, propane, NGLs and condensate	$	0.2	$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	0.6	$	—
Transportation, processing and other	$	0.8	$	2.4
Purchases of natural gas, propane and NGLs	$	6.6	$	7.8

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


	March 31, 2008		December 31, 2007
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	47.3	$	47.3
Accounts payable	$	36.6	$	53.3
Spectra Energy:
Accounts receivable	$	0.9	$	1.5
ConocoPhillips:
Accounts receivable	$	2.1	$	3.3
Accounts payable	$	1.5	$	2.3

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

6.	Goodwill

The change in the carrying amount of goodwill is as follows:


	March 31, 2008		December 31, 2007
	(Millions)
Beginning of period	$	80.2	$	29.3
Acquisition of MEG		1.9		50.9

End of period	$	82.1	$	80.2

The increases in goodwill during 2008 and 2007 were recognized in connection with our acquisition of the MEG subsidiaries from DCP Midstream, LLC.

7.	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.

•

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 exchange traded instruments (such as NYMEX crude oil, or natural gas futures) or over the counter instruments (such as over the counter, or OTC, natural gas contracts, or NGL contracts). The exchange traded instruments are generally executed on the NYMEX exchange with a highly rated broker dealer serving as the clearinghouse for individual transactions.

Within our Natural Gas Services segment we may use exchange traded derivative contracts, in addition to OTC derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices 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 based upon observable data. In instances where we utilize an interpolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 2. In certain limited instances, we may extrapolate based upon the last readily observable data, developing our own expectation of fair value. To the extent that we have utilized extrapolated data, 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 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.

In addition to the OTC contracts utilized within our Wholesale Propane Logistics segment, in order to mitigate a portion of our exposure to price changes in propane we may enter into exchange traded crude oil futures, which have an observable historical and expected future correlation to propane and NGL prices. As noted above, to the extent that we utilize exchange traded contracts, we generally classify such instruments within Level 1.

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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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, or 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.

The following table presents the financial instruments carried at fair value as of March 31, 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	$	0.4		$	—		$	0.4		$	—
Current unrealized gains on commodity derivative instruments	$	0.6		$	—		$	0.6		$	—
Long-term assets:
Restricted investments	$	220.4		$	—		$	220.4		$	—
Long-term unrealized gains on commodity derivative instruments	$	2.4		$	—		$	1.2		$	1.2
Current liabilities (a):
Commodity derivative instruments	$	(30.7	)	$	(8.9	)	$	(20.5	)	$	(1.3	)
Interest rate instruments	$	(10.4	)	$	—		$	(10.4	)	$	—
Long-term liabilities (b):
Commodity derivative instruments	$	(83.0	)	$	(13.3	)	$	(69.7	)	$	—
Interest rate instruments	$	(15.9	)	$	—		$	(15.9	)	$	—

(a)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.

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

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Changes in Level 3 Fair Value Measurements

The table below illustrates a rollforward of the amounts included in our condensed consolidated balance sheets 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.


	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 March 31, 2008			Net Unrealized Gains (Losses) Still Held Included in Earnings (b)
	(Millions)
Commodity derivative instruments:
Current assets	$	0.2		$	—		$	(0.2	)	$	—	$	—		$	—
Long-term assets	$	1.5		$	(0.3	)	$	—		$	—	$	1.2		$	(0.3	)
Current liabilities	$	(1.6	)	$	(0.5	)	$	—		$	0.8	$	(1.3	)	$	(0.5	)
Long-term liabilities	$	(0.2	)	$	—		$	0.2		$	—	$	—		$	—

(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.

(b)	Represents the amount of total gains or losses for the period, included in losses from commodity derivative activity, net, attributable to change in unrealized gains (losses) relating to assets and liabilities classified as Level 3 that are still held at March 31, 2008.

Debt

Long-term debt was as follows:


	March 31, 2008		December 31, 2007
	(Millions)
Revolving credit facility, weighted-average interest rate of 3.19% and 5.47%, respectively, due June 21, 2012 (a)	$	435.0	$	530.0
Term loan facility, interest rate of 2.88% and 5.05%, respectively, due June 21, 2012		220.0		100.0

Total long-term debt	$	655.0	$	630.0

(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 5.27% as of March 31, 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 sheets as of

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

March 31, 2008 and December 31, 2007. The unused portion of the revolving credit facility may be used for general corporate purposes and letters of credit. At March 31, 2008 and December 31, 2007, we had $25.3 million and $0.2 million of letters of credit outstanding under the Credit Agreement, respectively. As of March 31, 2008, the available capacity under our revolving credit facility was approximately $170.0 million.

Other Agreements

As of March 31, 2008, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $25.0 million, which reduces the amount of cash we may be required to post as collateral. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

9.	Partnership Equity and Distributions

General — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (defined below) to unitholders of record on the applicable record date, as determined by our general partner.

In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.3 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 the general partner to:

•

provide for the proper conduct of our business;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;

•

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights — Prior to June 2007, the general partner was entitled to 2% of all quarterly distributions that we make prior to our liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner has not participated in certain issuances of common units. Therefore, the general partner’s 2% interest has been diluted to 1.3% as of March 31, 2008.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash as pre-defined distribution targets have been achieved. The general partner’s incentive distribution rights were not reduced as a result of our March 2008 common limited partner unit offering, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its 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 the general partner’s incentive distribution rights.

Subordinated Units — All of the subordinated units are held by DCP Midstream, LLC. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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. We 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, or 3,571,428 units, converted into common units. Our board of directors 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.

Distributions of Available Cash during the Subordination Period — Our partnership agreement, after adjustment for the general partner’s relative ownership level, currently 1.3%, requires that we make distributions of Available Cash for any quarter during the subordination period in the following manner:

•

first, to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;

•

second, to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute 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 the general partner, in accordance with their pro rata interest, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;

•

fourth, to all unitholders and 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 the general partner, plus the general partner’s 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 the general partner, plus the general partner’s 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 the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders (the Fourth Target Distribution).

Distributions of Available Cash after the Subordination Period — Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, to all unitholders and 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 the general partner, plus the general partner’s 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 the general partner, plus the general partner’s 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 the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2008 and 2007:


Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
February 14, 2008	$	0.570	$	15.7
November 14, 2007		0.550		14.7
August 14, 2007		0.530		12.4
May 15, 2007		0.465		8.6
February 14, 2007		0.430		7.8

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

10.

Risk Management and Hedging Activities

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


	Three Months Ended March 31,
	2008			2007
	(Millions)
Commodity cash flow hedges:
(Losses) gains reclassified into earnings	$	(0.3	)	$	1.3
Commodity derivative activity:
Unrealized losses from derivative activity	$	(28.0	)	$	(2.9	)
Realized losses from derivative activity	$	(9.1	)	$	(0.1	)
Interest rate cash flow hedges:
(Losses) gains reclassified into earnings	$	(0.1	)	$	0.1


	March 31, 2008			December 31, 2007
	(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(2.2	)	$	(2.6	)
Interest rate cash flow hedges:
Net deferred losses in AOCI	$	(26.0	)	$	(12.3	)

For the three months ended March 31, 2008 and 2007, 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 March 31, 2008, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $25.0 million. This letter of credit reduces the amount of cash we may be required to post as collateral. As of March 31, 2008, we posted cash collateral with certain counterparties to our commodity derivative instruments of approximately $7.1 million, which is included in other current assets on the condensed consolidated balance sheet.

Commodity Cash Flow Protection Activities — 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 accumulated in AOCI. During the period in which the hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were reclassified to the condensed consolidated statements of operations in the same accounts as the item being hedged.

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. Therefore, we are using the mark-to-market method of accounting for all commodity derivative instruments. As a result, the remaining net loss deferred in AOCI will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the hedged transactions impact earnings. Deferred net losses of $1.0 million are expected to be reclassified during the next 12 months. Subsequent to July 1, 2007, the changes in fair value of financial derivatives are included in gains and losses from commodity derivative activity in the condensed consolidated statements of operations. 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

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 sheets. Deferred net losses of $10.1 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 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 management expects to fully perform under the terms of the agreements.

11.

Net Income per Limited Partner Unit

Our net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to income allocated to predecessor operations and incentive distributions paid to the general partner.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds the First Target Distribution Level, it will have the impact of reducing net income per LPU. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of Available Cash and not earnings. In periods in which our aggregate net income does not exceed the First Target Distribution Level, there is no impact on our calculation of earnings per LPU. During the three months ended March 31, 2008, no additional earnings were allocated to the general partner. During the three months ended March 31, 2007, our aggregate net income per LPU exceeded the Third Target Distribution level, and as a result we allocated $1.9 million in additional earnings to the general partner.

Basic and diluted net income per LPU is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions as described above, by the weighted-average number of outstanding LPUs during the period.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The following table illustrates our calculation of net income per LPU:


	Three Months Ended March 31,
	2008			2007
	(Millions)
Net (loss) income	$	(6.5	)	$	15.8
Less:
Net income attributable to predecessor operations		—			(3.3	)

Net (loss) income attributable to the partnership		(6.5	)		12.5
Less: General partner interest in net income		(1.7	)		(0.3	)

Limited partners’ interest in net (loss) income		(8.2	)		12.2
Less: Additional earnings allocation to general partner		—			(1.9	)

Net (loss) income available to limited partners	$	(8.2	)	$	10.3

Net (loss) income per LPU — basic and diluted	$	(0.33	)	$	0.58

12.

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 results of operations, financial position, or cash flows. See Note 16 in Item 8 of our 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 predecessors. See the “Indemnification” section of Note 5 in Item 8 of our 2007 Form 10-K for additional details.

13.

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.

Natural Gas Services — The Natural Gas Services segment consists of (1) the Northern Louisiana system; (2) the Southern Oklahoma system that was acquired in May 2007; (3) our 25% limited liability company interest in East Texas, our 40% limited liability company interest in Discovery, and the Swap acquired in July 2007; and (4) the assets of the MEG subsidiaries that were acquired in August 2007.

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of six owned rail terminals, one of which is currently idle, one leased marine terminal, one pipeline terminal and access to several open-access pipeline terminals. We generally offer our customers the ability to obtain propane supply volumes from us in the winter months that are generally significantly greater than their purchase of propane from us in the summer.

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. Gross margin is a performance measure utilized by management to monitor the business of each segment.

The following tables set forth our segment information:

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Three Months Ended March 31, 2008


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenue	$	133.4		$	201.7		$	2.6		$	—		$	337.7

Gross margin (a)	$	(2.5	)	$	8.6		$	1.9		$	—		$	8.0
Operating and maintenance expense		(7.7	)		(2.7	)		(0.2	)		—			(10.6	)
Depreciation and amortization expense		(7.8	)		(0.3	)		(0.4	)		—			(8.5	)
General and administrative expense		—			—			—			(5.5	)		(5.5	)
Earnings from equity method investments		16.8			—			0.4			—			17.2
Interest income		—			—			—			1.6			1.6
Interest expense		—			—			—			(8.1	)		(8.1	)
Non-controlling interest in income		(0.6	)		—			—			—			(0.6	)

Net (loss) income	$	(1.8	)	$	5.6		$	1.7		$	(12.0	)	$	(6.5	)

Capital expenditures	$	8.3		$	0.8		$	0.1		$	—		$	9.2

Three Months Ended March 31, 2007


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenues	$	83.5		$	151.8		$	1.9		$	—		$	237.2

Gross margin (a)	$	14.2		$	10.8		$	1.3		$	—		$	26.3
Operating and maintenance expense		(3.3	)		(3.2	)		(0.1	)		—			(6.6	)
Depreciation and amortization expense		(2.9	)		(0.2	)		(0.3	)		—			(3.4	)
General and administrative expense		—			—			—			(4.8	)		(4.8	)
Earnings from equity method investments		6.2			—			0.2			—			6.4
Interest income		—			—			—			1.7			1.7
Interest expense		—			—			—			(3.8	)		(3.8	)

Net income (loss)	$	14.2		$	7.4		$	1.1		$	(6.9	)	$	15.8

Capital expenditures	$	1.8		$	1.2		$	0.4		$	—		$	3.4


	March 31, 2008		December 31, 2007
	(Millions)
Segment long-term assets:
Natural Gas Services	$	715.6	$	710.7
Wholesale Propane Logistics		53.3		52.6
NGL Logistics		34.8		34.8
Other (b)		223.6		104.1

Total long-term assets		1,027.3		902.2
Current assets		205.2		218.5

Total assets	$	1,232.5	$	1,120.7

(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

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

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

14.

Supplemental Cash Flow Information


	Three Months Ended March 31,
	2008		2007
	(Millions)
Cash paid for interest, net of amounts capitalized	$	8.6	$	4.3
Non-cash additions of property, plant and equipment	$	2.1	$	—

15.

Subsequent Events

During the second quarter of 2008, we issued a $25.0 million letter of credit to a counterparty to our commodity derivative instruments, which reduces the cash collateral we may be required to post. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

Thomas E. Long, vice president and chief financial officer of our general partner, resigned effective April 30, 2008. Our general partner is conducting a search for Mr. Long’s replacement.

In April 2008, we received $1.5 million from a supplier to our Wholesale Propane Logistics segment related to the early termination of its supply agreement. This agreement was set to expire in the second quarter of 2009.

On April 24, 2008, the board of directors of the General Partner declared a quarterly distribution of $0.59 per unit, payable on May 15, 2008 to unitholders of record on May 8, 2008. This distribution of $0.59 per unit places us in the Fourth Target Distribution level (see Note 9 for discussion of distributions of available cash).

In April 2008, we received a distribution of $10.4 million from Discovery for the first quarter of 2008.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our condensed consolidated financial statements and notes included elsewhere in this Form 10-Q and the consolidated financial statements and notes thereto included in our 2007 Form 10-K. We refer to the our 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, and our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery, as well as a non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, which we acquired from DCP Midstream, LLC in July 2007, collectively as our “predecessor.” The financial information contained herein includes, for each period presented, our accounts, and those of our predecessor.

Overview

We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We operate in three business segments:

•

our Natural Gas Services segment, which consists of (1) our Northern Louisiana natural gas gathering, processing and transportation system; (2) our Southern Oklahoma system acquired in May 2007; (3) our % limited liability company interest in East Texas, our limited liability company interest in Discovery, and the Swap, acquired in July 2007 from DCP Midstream, LLC; and (4) our Colorado and Wyoming systems, acquired in August 2007 from DCP Midstream, LLC, which were acquired by DCP Midstream, LLC from Momentum Energy Group, Inc. in August 2007 (referred to as the MEG acquisition);

•

our Wholesale Propane Logistics segment, which consists of six owned rail terminals, one of which is currently idle, one leased marine terminal, one pipeline terminal that became operational in May 2007, and access to several open-access pipeline terminals; and

•

our NGL Logistics segment, which consists of our interests in three NGL pipelines.

Recent 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.

Thomas E. Long, vice president and chief financial officer of our general partner, resigned effective April 30, 2008. Our general partner is currently conducting a search for Mr. Long’s replacement.

On April 24, 2008, the board of directors of the General Partner declared a quarterly distribution of $0.59 per unit, payable on May 15, 2008 to unitholders of record on May 8, 2008. This distribution of $0.59 per unit places us in the Fourth Target Distribution level (see Note 9 of the Notes to Condensed Consolidated Financial Statements in Item 1. “Financial Statements” for discussion of distributions of available cash).

In April 2008, we received distributions of $10.4 million from Discovery, in March 2008 we received distributions of $7.8 million from East Texas, and in March 2008 we paid a contribution of $0.9 million to East Texas to fund capital expansion.

In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.3 million, net of offering costs.

Factors That Significantly Affect Our Results

In July 2007, we acquired a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery and the Swap, which are collectively referred to as our predecessor, from DCP Midstream, LLC, in a transaction among entities under common control. Accordingly, our financial information includes the historical results of our predecessor for each period presented. Prior to July 2007, our financial statements do not give effect to various items that affected our results

of operations and liquidity following this acquisition, including the indebtedness we incurred in conjunction with the closing of this acquisition, which increased our interest expense from the interest expense reflected in our historical financial statements.

Our results of operations for our Natural Gas Services segment are impacted by increases and decreases in the volume of natural gas that we gather and transport through our systems, which we refer to as throughput. Throughput and capacity utilization rates generally are driven by wellhead production and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate.

Our results of operations for our Natural Gas Services segment are also impacted by the fees we receive and the margins we generate. Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, commodity pricing environment at the time the contract is executed and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to natural gas, NGL and condensate prices, may change as a result of producer preferences, our expansion in regions where certain types of contracts are more common and other market factors.

We have mitigated a portion of the anticipated commodity price risk associated with the equity volumes from our gathering and processing operations and certain wholesale propane sales, for both our consolidated entities and our proportionate share of exposure for our equity method investments, through 2013 with natural gas, NGL and crude oil swaps. We mark these derivative instruments to market through current period earnings based upon their fair value. While the swaps mitigate the variability of our future cash flows resulting from changes in commodity prices, the mark-to-market method of accounting significantly increases the volatility of our net income because we recognize, in current period operating revenues, all non-cash gains and losses from the changes in the fair value of these derivatives.

We primarily use crude oil swaps to mitigate the NGL commodity price risk. As a result, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. We also continue to have price risk exposure related to the portion of our equity volumes that are not covered by these derivatives. In addition, we will be required to provide cash collateral or letters of credit if the fair value of a derivative exceeds the collateral threshold set by the counterparty. Our collateral requirements may be significant.

For the three months ended March 31, 2008, the net loss recorded in operating revenues for these derivatives was $37.4 million. Of the loss, $9.1 million was related to cash settlements during 2008. The fair value of these derivatives was a net liability of $110.7 million as of March 31, 2008.

Additionally, our results of operations for our Natural Gas Services segment are impacted by market conditions causing variability in natural gas prices.

Our results of operations for our Wholesale Propane Logistics segment are impacted by our ability to balance our purchases and sales of propane, which may increase our exposure to commodity price risks, and by the impact on volume and pricing from weather conditions in the Midwest and northeastern sections of the United States. Our sales of propane may decline when these areas experience periods of milder weather in the winter months, which is when the demand for propane is generally at its highest.

Our results of operations for our NGL Logistics segment are impacted by the throughput volumes of the NGLs we transport on our NGL pipelines. Our NGL pipelines transport NGLs exclusively on a fee basis.

The Black Lake pipeline has experienced increased operating costs due to pipeline integrity testing that commenced in 2005 and has continued into 2008. We expect that our results of operations related to our equity interest in the Black Lake pipeline will benefit in 2008 from the completion of this pipeline integrity testing, although it is possible that the integrity testing will result in the need for pipeline repairs, in which case the operations of this pipeline may be interrupted while the repairs are being made. DCP Midstream, LLC has agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions required to be made by us to Black Lake associated with repairing the Black Lake pipeline that are determined to be necessary as a result of the pipeline integrity testing through June 2008. Pipeline integrity testing and repairs are our responsibility and are recognized as operating and maintenance expense. Any reimbursement of these expenses from DCP Midstream, LLC will be recognized by us as a capital contribution. We have not made any capital contributions to Black Lake associated with repairing the Black Lake pipeline.

During 2006, we entered into agreements with ConocoPhillips, which expanded the gathering and transportation services between us. As a result of these agreements, 13 new wells were added to our system during the three months ended March 31, 2008 and 14 new wells were added to our system during the year ended December 31, 2007.

Discovery has signed definitive agreements with Chevron Corporation, Royal Dutch Shell plc, and StatoilHydro ASA to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’

production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 MMcf/d. In October 2007, Chevron announced that it will face delays and that first production will commence in the third quarter of 2009. In conjunction with our acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for remaining costs for the Tahiti pipeline lateral expansion.

Finally, we intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

Our Operations

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into our Natural Gas Services segment, our Wholesale Propane Logistics segment and our NGL Logistics segment.

Natural Gas Services Segment

Results of operations from our Natural Gas Services segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our gathering, processing and pipeline systems; the volumes of NGLs and condensate sold; and the level of our realized natural gas, NGL and condensate prices. We generate our revenues and our gross margin for our Natural Gas Services segment principally from contracts that contain a combination of the following arrangements:

•

Fee-based arrangements — Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing or transporting natural gas; and transporting NGLs. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

•

Percentage-of-proceeds/index arrangements — Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percentage-of-proceeds/index arrangements correlate directly with the price of natural gas and/or NGLs.

In addition to the above contract types, our equity method investments also generate equity earnings for our Natural Gas Services segment under keep-whole arrangements. Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, sell the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas received. Under this type of contract, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds the operating costs of our equity method investments. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.

We have mitigated a portion of our anticipated natural gas, NGL and condensate commodity price risk associated with the equity volumes from our gathering and processing operations through 2013 with natural gas and crude oil swaps. With these swaps, we expect our cash flow exposure to commodity price movements to be reduced. For additional information regarding our derivative activities, please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities” in our 2007 Form 10-K and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report on Form 10-Q.

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We are using the mark-to-market method of accounting for all commodity derivative financial instruments, which has significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.

The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in Colorado, Louisiana, Oklahoma, Texas, Wyoming and the Gulf of Mexico. The Pelico system also receives natural gas produced in Texas through its interconnect with other pipelines that transport natural gas from Texas into western Louisiana. These areas have experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. Our primary supplier of natural gas in our Natural Gas Services segment represented approximately 24% of the 449 MMcf/d of natural gas supplied to this system during the three months ended March 31, 2008. We actively seek new supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage, or by obtaining natural gas that has been released from other gathering systems.

We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to DCP Midstream, LLC or its affiliates, or to third parties. In addition, under our merchant arrangements, we use a subsidiary of DCP Midstream, LLC as our agent to purchase natural gas from third parties at pipeline interconnect points, as well as residue gas from our Minden and Ada processing plants, and then resell the aggregated natural gas to third parties. We also have entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that requires DCP Midstream, LLC to supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index based price less a contractually agreed to marketing fee. In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential plus a fixed fuel charge and other related adjustments. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing financial derivatives to swap this fixed price risk back to market index. We may enter into financial derivatives to lock in price differentials across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for using mark-to-market accounting. We also gather, process and transport natural gas under fee-based transportation contracts.

Wholesale Propane Logistics Segment

We operate a wholesale propane logistics business in the Midwest and northeastern United States. We purchase large volumes of propane supply from natural gas processing plants and fractionation facilities, and crude oil refineries, primarily located in the Texas and Louisiana Gulf Coast area, Canada and other international sources, and transport these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities in the Midwest and the northeastern areas of the United States. We identify primary suppliers as those individually representing 10% or more of our total propane supply. Our three primary suppliers of propane represented approximately 96% of our propane supplied during the three months ended March 31, 2008. We sell propane on a wholesale basis to retail propane distributors who in turn resell propane to their retail customers.

Due to our multiple propane supply sources, annual and long-term propane supply purchase arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our retail propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when their retail customers generally consume the most propane for home heating. In particular, we generally offer our customers the ability to obtain propane supply volumes from us in the winter months that are generally significantly greater than their purchase of propane from us in the summer. We believe these factors generally allow us to maintain our generally favorable relationship with our customers.

We manage our wholesale propane margins by selling propane to retail propane distributors under annual sales agreements negotiated each spring that specify floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase arrangements. In the event that a retail propane distributor desires to purchase propane from us on a fixed price basis, we sometimes enter into fixed price sales agreements with terms of up to one year, and we manage this commodity price risk by entering into either offsetting physical purchase agreements or financial derivative instruments, with either DCP Midstream, LLC or third parties, that typically match the quantities of propane subject to these fixed price sales agreements. Our portfolio of multiple supply sources and storage capabilities allows us to actively manage our propane supply purchases and to lower the aggregate cost of supplies. In addition, we may use financial derivatives to manage the value of our propane inventories.

NGL Logistics Segment

Our pipelines provide transportation services to customers on a fee basis. We have entered into contractual arrangements with DCP Midstream, LLC that require DCP Midstream, LLC to pay us to transport NGLs pursuant to a fee-based rate that is applied to the volumes transported. Therefore, the results of operations for this business segment are generally dependent upon the volume of product transported and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines; rather, the shipper retains title and the associated commodity price risk. For the Seabreeze and Wilbreeze pipelines, we are responsible for any line loss or gain in NGLs. For the Black Lake pipeline, any line loss or gain in NGLs is allocated to the shipper. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the mixed NGLs from the natural gas. As a result, we have experienced periods in the past, and will likely experience periods in the future, in which higher natural gas prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. In the markets we serve, our pipelines are the sole pipeline facility transporting NGLs from the supply source.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) volumes; (2) gross margin, including segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) EBITDA; and (5) distributable cash flow. Gross margin, segment gross margin, EBITDA and distributable cash flow measurements are not accounting principles generally accepted in the United States of America, or GAAP, financial measures. We provide reconciliations of these non-GAAP measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP. Our gross margin, segment gross margin, EBITDA and distributable cash flow may not be comparable to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the same manner.

Volumes — We view throughput volumes for our Natural Gas Services segment and our NGL Logistics segment, and sales volumes for our Wholesale Propane Logistics segment as important factors affecting our profitability. We gather and transport some of the natural gas and NGLs under fee-based transportation contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or to increase throughput levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain new supplies of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by: (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines; and (2) our ability to compete for volumes from successful new wells in other areas. The throughput volumes of NGLs on our pipelines are substantially dependent upon the quantities of NGLs produced at our processing plants, as well as NGLs produced at other processing plants that have pipeline connections with our NGL pipelines. We regularly monitor producer activity in the areas we serve and our pipelines, and pursue opportunities to connect new supply to these pipelines.

Gross Margin — We view our gross margin as an important performance measure of the core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.

We define gross margin as total operating revenues less purchases of natural gas, propane and NGLs, and we define segment gross margin for each segment as total operating revenues for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross margin is included as a supplemental disclosure because it is a primary performance measure used by management, as it represents the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

Our gross margin and segment gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin and segment gross margin in the same manner. The following table sets forth our reconciliation of certain non-GAAP measures:


	Three Months Ended March 31,
	2008			2007
	(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of net (loss) income to gross margin:
Net (loss) income	$	(6.5	)	$	15.8
Interest expense		8.1			3.8
Operating and maintenance expense		10.6			6.6
Depreciation and amortization expense		8.5			3.4
General and administrative expense		5.5			4.8
Non-controlling interest in income		0.6			—
Interest income		(1.6	)		(1.7	)
Earnings from equity method investments		(17.2	)		(6.4	)

Gross margin	$	8.0		$	26.3

Reconciliation of segment net income to segment gross margin:
*Natural Gas Services segment:*
Segment net (loss) income	$	(1.8	)	$	14.2
Operating and maintenance expense		7.7			3.3
Depreciation and amortization expense		7.8			2.9
Non-controlling interest in income		0.6			—
Earnings from equity method investments		(16.8	)		(6.2	)

Segment gross margin	$	(2.5	)	$	14.2

*Wholesale Propane Logistics segment:*
Segment net income	$	5.6		$	7.4
Operating and maintenance expense		2.7			3.2
Depreciation and amortization expense		0.3			0.2

Segment gross margin	$	8.6		$	10.8

*NGL Logistics segment:*
Segment net income	$	1.7		$	1.1
Operating and maintenance expense		0.2			0.1
Depreciation and amortization expense		0.4			0.3
Earnings from equity method investments		(0.4	)		(0.2	)

Segment gross margin	$	1.9		$	1.3

Operating and Maintenance and General and Administrative Expense — Operating and maintenance expense are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repairs and maintenance, lease expenses, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are relatively independent of the volumes through our systems, but may fluctuate depending on the activities performed during a specific period.

A substantial amount of our general and administrative expense is incurred from DCP Midstream, LLC. 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. We anticipate incurring a total of $9.7 million under the Omnibus Agreement in 2008. During the three months ended March 31, 2008 and 2007, we incurred fees of $2.4 million and $1.7 million, respectively, under the Omnibus Agreement and other fees paid to DCP Midstream, LLC of $0.5 million and $0.6 million, respectively. We also incurred third party general and administrative fees of $2.6 million and $2.5 million for the three months ended March 31, 2008 and 2007, respectively.

The Omnibus Agreement also addresses the following matters:

•

DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;

•

DCP Midstream, LLC’s obligation to continue to maintain its credit support for our obligations related to derivative financial instruments, such as commodity derivative instruments, to the extent that such credit support arrangements were in effect as of December 7, 2005 until the earlier of December 7, 2010 or when we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and

•

DCP Midstream, LLC’s obligation to continue to maintain its credit support for our obligations related to commercial contracts with respect to its business or operations that were in effect at December 7, 2005 until the expiration of such contracts.

All of the fees under the Omnibus Agreement will be adjusted annually by the percentage change in the Consumer Price Index for the applicable year. In addition, our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses, with the concurrence of the special committee of DCP Midstream GP, LLC’s board of directors.

We also incurred third party general and administrative expenses, which were primarily related to compensation and benefit expenses of the personnel who provide direct support to our operations. Also included are expenses associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, due diligence and acquisition costs, costs associated with the Sarbanes-Oxley Act of 2002, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and director compensation.

East Texas and Discovery also pay fees to DCP Midstream, LLC and Williams, respectively, for direct costs incurred on their behalf. These fees reduce the amount of cash available from East Texas and Discovery for distribution to us.

EBITDA and Distributable Cash Flow — We define EBITDA as net income less interest income, plus interest expense, income tax expense and depreciation and amortization expense. EBITDA is used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures. EBITDA is also a financial measurement that is reported to our lenders, and used as a gauge for compliance with our financial covenants under our credit facility, which requires us to maintain: (1) a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters following the consummation of asset acquisitions in the midstream energy business (including the quarter in which such acquisition is consummated), of not more than 5.50 to 1.0; and (2) an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as is defined by the Amended Credit Agreement) of equal to or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. Our EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.

EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

•

financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; and

•

viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.

We define distributable cash flow as net cash provided by operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities (see “— Liquidity and

Capital Resources” for further definition of maintenance capital expenditures). Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long term, our operating capacity or revenues. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing distributable cash flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices. Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner. Our distributable cash flow may not be comparable to a similarly titled measure of another company because other entities may not calculate distributable cash flow in the same manner. The following table sets forth our reconciliation of EBITDA to its most directly comparable financial measure calculated in accordance with GAAP:


	Three Months Ended March 31,
	2008			2007
	(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of net (loss) income to EBITDA:
Net (loss) income	$	(6.5	)	$	15.8
Interest income		(1.6	)		(1.7	)
Interest expense		8.1			3.8
Depreciation and amortization expense		8.5			3.4

EBITDA	$	8.5		$	21.3

Reconciliation of net cash provided by operating activities to EBITDA:
Net cash provided by operating activities	$	25.1		$	19.8
Interest income		(1.6	)		(1.7	)
Interest expense		8.1			3.8
Earnings from equity method investments, net of distributions		(2.0	)		0.8
Net changes in operating assets and liabilities		(21.0	)		(1.9	)
Other, net		(0.1	)		0.5

EBITDA	$	8.5		$	21.3

Fair Value Measurements — We utilize fair value to measure our financial instruments, including commodity and interest rate swap derivative assets and liabilities, as well as our short-term and restricted investments. 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 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. We have a process for determining fair values, which 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. While we believe that our valuation methods are appropriate and consistent with other marketplace participants, representing an accurate fair value for each instrument, 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.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in Item 7 in our 2007 Form 10-K. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three months ended March 31, 2008 are the same as those described in our 2007 Form 10-K.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2008 and 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion:


	Three Months Ended March 31,						Variance 2008 vs. 2007
	2008 (a)			2007			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services (b)	$	133.4		$	83.5		$	49.9		59.8	%
Wholesale Propane Logistics		201.7			151.8			49.9		32.9	%
NGL Logistics		2.6			1.9			0.7		36.8	%

Total operating revenues		337.7			237.2			100.5		42.4	%

Gross margin (c):
Natural Gas Services		(2.5	)		14.2			(16.7	)	*
Wholesale Propane Logistics		8.6			10.8			(2.2	)	(20.4)	%
NGL Logistics		1.9			1.3			0.6		46.2	%

Total gross margin		8.0			26.3			(18.3	)	(69.6)	%
Operating and maintenance expense		(10.6	)		(6.6	)		4.0		60.6	%
General and administrative expense		(5.5	)		(4.8	)		0.7		14.6	%
Earnings from equity method investments (d)		17.2			6.4			10.8		168.8	%
Non-controlling interest in income		(0.6	)		—			0.6		100.0	%

EBITDA (e)		8.5			21.3			(12.8	)	(60.1)	%
Depreciation and amortization expense		(8.5	)		(3.4	)		5.1		150.0	%
Interest income		1.6			1.7			(0.1	)	(5.9)	%
Interest expense		(8.1	)		(3.8	)		4.3		113.2	%

Net (loss) income	$	(6.5	)	$	15.8		$	(22.3	)	*

Operating data:
Natural gas throughput (MMcf/d) (d)		829			701			128		18.3	%
NGL gross production (Bbls/d) (d)		25,191			19,117			6,074		31.8	%
Propane sales volume (Bbls/d)		33,914			35,358			(1,444	)	(4.1)	%
NGL pipelines throughput (Bbls/d) (d)		31,876			27,458			4,418		16.1	%

*	Percentage change is not meaningful.

(a)	Includes the results from the Southern Oklahoma and MEG acquisitions, from their respective acquisition dates in May and August of 2007, respectively.

(b)	Includes the effect of the acquisition of the Swap entered into by DCP Midstream, LLC in March 2007. The Swap was for a total of approximately 1.9 million barrels through 2012, at $66.72 per barrel.

(c)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “How We Evaluate Our Operations” above.

(d)	Includes our proportionate share of the throughput volumes and earnings of Black Lake, East Texas and Discovery. Earnings for Discovery and Black Lake include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the investments.

(e)	EBITDA consists of net (loss) income less interest income plus interest expense, and depreciation and amortization expense. Please read “How We Evaluate Our Operations” above.

Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

Total Operating Revenues — Total operating revenues increased in 2008 compared to 2007, primarily due to the following:

•

$82.2 million increase attributable primarily to higher natural gas, NGL and condensate sales volumes, primarily as a result of the MEG and Southern Oklahoma acquisitions, as well as increased commodity prices, for our Natural Gas Services segment;

•

$48.6 million increase attributable to increased propane prices, offset by decreased propane sales volumes for our Wholesale Propane Logistics segment;

•

$4.8 million increase in transportation, processing and other revenue, primarily attributable to the MEG acquisition in our Natural Gas Services segment; and

•

$0.6 million increase attributable primarily to changes in contract mix and increased volumes for our NGL Logistics segment; offset by

•

$35.7 million decrease related to commodity derivative activity, a decrease of $1.6 million of which is included in sales of natural gas, NGLs and condensate, and a decrease of $34.1 million of which is included in losses from commodity derivative activity.

Gross Margin — Gross margin decreased in 2008 compared to 2007, primarily due to the following:

•

$16.7 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity and lower NGL and condensate production across our Northern Louisiana system, offset by an increase in natural gas, NGL and condensate production as a result of the MEG and Southern Oklahoma acquisitions, increased commodity prices and changes in contract mix; and

•

$2.2 million decrease for our Wholesale Propane Logistics segment due to lower per unit margins, decreased non-cash lower of cost or market inventory adjustments recognized in 2008 and lower sales volumes, partially offset by an increase related to commodity derivative activity; offset by

•

$0.6 million increase for our NGL Logistics segment attributable primarily due to changes in contract mix and increased volumes.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2008 compared to 2007, primarily as a result of the MEG and Southern Oklahoma acquisitions in May and August 2007 in our Natural Gas Services segment, partially offset by decreased labor and benefits in our Wholesale Propane Logistics segment.

General and Administrative Expense — General and administrative expense increased in 2008 compared to 2007, primarily as a result of increased fees paid to DCP Midstream, LLC under the Omnibus Agreement, mainly due to acquisitions, partially offset by decreased labor and benefits due to lower long-term incentive plan expenses.

Earnings from Equity Method Investments — Earnings from equity method investments increased in 2008 compared to 2007, due to increased equity earnings of $4.1 million from East Texas, $6.5 million from Discovery and $0.2 million from Black Lake.

Non-Controlling Interest in Income — Non-controlling interest in income reduced income by $0.6 million in 2008, and represents the non-controlling interest holders’ portion of the net income of our Collbran Valley Gas Gathering system joint venture, acquired in the MEG acquisition.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2008 compared to 2007, primarily as a result of the 2007 acquisitions.

Interest Expense — Interest expense increased in 2008 compared to 2007, primarily as a result of the financing of the 2007 acquisitions.

Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system acquired in May 2007, a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery, and the Swap, acquired in July 2007, and certain subsidiaries of MEG, acquired in August 2007:


	Three Months Ended March 31,						Variance 2008 vs. 2007
	2008 (a)			2007			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	160.8		$	80.2		$	80.6		100.5	%
Transportation, processing and other		10.7			6.0			4.7		78.3	%
Losses from commodity derivative activity (b)		(38.1	)		(2.7	)		35.4		*

Total operating revenues		133.4			83.5			49.9		59.8	%
Purchases of natural gas and NGLs		135.9			69.3			66.6		96.1	%

Segment gross margin (c)		(2.5	)		14.2			(16.7	)	*
Operating and maintenance expense		(7.7	)		(3.3	)		4.4		133.3	%
Depreciation and amortization expense		(7.8	)		(2.9	)		4.9		169.0	%
Earnings from equity method investments (d)		16.8			6.2			10.6		171.0	%
Non-controlling interest in income		(0.6	)		—			0.6		100.0	%

Segment net (loss) income	$	(1.8	)	$	14.2		$	(16.0	)	*

Operating data:
Natural gas throughput (MMcf/d) (d)		829			701			128		18.3	%
NGL gross production (Bbls/d) (d)		25,191			19,117			6,074		31.8	%

*	Percentage change is not meaningful.

(a)	Includes the results from the Southern Oklahoma and MEG acquisitions, from their respective acquisition dates in May and August of 2007, respectively.

(b)	Includes the effect of the acquisition of the Swap entered into by DCP Midstream, LLC in March 2007. The Swap was for a total of approximately 1.9 million barrels through 2012, at $66.72 per barrel.

(c)	Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “How We Evaluate Our Operations” above.

(d)	Includes our proportionate share of the throughput volumes and earnings of East Texas and Discovery, and the amortization of the net difference between the carrying amount of Discovery and the underlying equity of Discovery, for all periods presented.

Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

Total Operating Revenues — Total operating revenues increased in 2008 compared to 2007, primarily due to the following:

•

$42.5 million increase primarily attributable to higher natural gas, NGL and condensate sales volumes, primarily as a result of the Southern Oklahoma and MEG acquisitions; and

•

$39.7 million increase attributable to an increase in commodity prices; and

•

$4.7 million increase in transportation, processing and other revenue primarily as a result of the MEG acquisition; offset by

•

$37.0 million decrease related to commodity derivative activity, a decrease of $1.6 million of which is included in sales of natural gas, NGLs and condensate, and a decrease of $35.4 million of which is included in losses from commodity derivative activity.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2008 compared to 2007, primarily due to increased natural gas purchased volumes, primarily as a result of the MEG and Southern Oklahoma acquisitions, and higher costs of raw natural gas supply, driven by higher commodity prices.

Segment Gross Margin — Segment gross margin decreased in 2008 compared to 2007, primarily as a result of the following:

•

$37.0 million decrease related to commodity derivative activity; offset by

•

$14.0 million increase primarily attributable to an increase in natural gas, NGL and condensate production as a result of the MEG and Southern Oklahoma acquisitions, partially offset by lower NGL and condensate production across our Northern Louisiana system;

•

$3.2 million increase due to increased commodity prices; and

•

$3.1 million increase primarily attributable to changes in contract mix.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2008 compared to 2007, primarily as a result of the MEG and Southern Oklahoma acquisitions.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2008 compared to 2007, primarily as a result of the Southern Oklahoma and MEG acquisitions.

Earnings from Equity Method Investments — Earnings from equity method investments increased in 2008 compared to 2007, due to an increase in equity earnings of $6.5 million from Discovery and an increase in equity earnings of $4.1 million from East Texas. Increased equity earnings were primarily the result of the following variances, each representing 100% of the earnings drivers for East Texas and Discovery:

•

Increased equity earnings from East Texas were the result of an increase in East Texas’ net income of $16.8 million, due primarily to a $10.5 million increase as a result of higher commodity prices, a $5.5 million increase due to an increase in natural gas volumes, and a $2.1 million increase due to increased fee-based revenue, partially offset by an increase in operating expenses of $1.1 million.

•

Increased equity earnings from Discovery were the result of an increase in Discovery’s net income of $16.2 million, due primarily to $14.9 million higher product sales margins resulting primarily from sharply increased per-unit margins and higher NGL sales volumes and $2.9 million for higher other income, net, partially offset by $1.2 million higher general and administrative expense.

NGL production and natural gas transported and/or processed increased in 2008 compared to 2007, due primarily to increased volumes from Discovery and East Texas and increased volumes from the MEG and Southern Oklahoma acquisitions, partially offset by decreased volumes from Pelico.

Results of Operations — Wholesale Propane Logistics Segment

This segment includes our propane transportation facilities, which includes six owned rail terminals, one of which is currently idle, one leased marine terminal, one pipeline terminal, and access to several open-access pipeline terminals:


	Three Months Ended March 31,						Variance 2008 vs. 2007
	2008			2007			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of propane	$	200.7		$	152.1		$	48.6		32.0	%
Gains (losses) from commodity derivative activity		1.0			(0.3	)		1.3		*

Total operating revenues		201.7			151.8			49.9		32.9	%
Purchases of propane		193.1			141.0			52.1		37.0	%

Segment gross margin (a)		8.6			10.8			(2.2	)	(20.4)	%
Operating and maintenance expense		(2.7	)		(3.2	)		(0.5	)	(15.6)	%
Depreciation and amortization expense		(0.3	)		(0.2	)		0.1		50.0	%

Segment net income	$	5.6		$	7.4		$	(1.8	)	(24.3)	%

Operating data:
Propane sales volume (Bbls/d)		33,914			35,358			(1,444	)	(4.1)	%

*	Percentage change is not meaningful.

(a)	Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “How We Evaluate Our Operations” above.

Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

Total Operating Revenues — Total operating revenues increased in 2008 compared to 2007, primarily due to the following:

•

$53.7 million increase attributable to higher propane prices; and

•

$1.3 million increase related to commodity derivative activity; offset by

•

$5.1 million decrease attributable to lower propane sales volumes as a result of milder weather in portions of our markets in 2008, supply disruptions and lower demand as a result of higher prices.

Purchases of Propane — Purchases of propane increased in 2008 compared to 2007, primarily due to increased prices and the completion of the Midland terminal in May 2007, offset by decreased purchased volumes as a result of milder weather in portions of our markets in 2008 and supply disruptions.

Segment Gross Margin — Segment gross margin decreased in 2008 compared to 2007, primarily as a result of lower per unit margins, decreased non-cash lower of cost or market inventory adjustments recognized in 2008 and lower sales volumes, partially offset by an increase related to commodity derivative activity.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2008 compared to 2007, primarily due to decreased labor and benefits.

Results of Operations — NGL Logistics Segment

This segment includes our Seabreeze and Wilbreeze NGL transportation pipelines and our 45% interest in Black Lake:


	Three Months Ended March 31,						Variance 2008 vs. 2007
	2008			2007			Increase (Decrease)		Percent
	(Millions, except as indicated)
Operating revenues:
Sales of NGLs	$	1.2		$	0.6		$	0.6	100.0	%
Transportation, processing and other		1.4			1.3			0.1	7.7	%

Total operating revenues		2.6			1.9			0.7	36.8	%
Purchases of NGLs		0.7			0.6			0.1	16.7	%

Segment gross margin (a)		1.9			1.3			0.6	46.2	%
Operating and maintenance expense		(0.2	)		(0.1	)		0.1	100.0	%
Depreciation and amortization expense		(0.4	)		(0.3	)		0.1	33.3	%
Earnings from equity method investment (b)		0.4			0.2			0.2	100.0	%

Segment net income	$	1.7		$	1.1		$	0.6	54.5	%

Operating data:
NGL pipelines throughput (Bbls/d) (b)		31,876			27,458			4,418	16.1	%

(a)	Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “How We Evaluate Our Operations” above.

(b)	Includes 45% of the throughput volumes and earnings of Black Lake and the amortization of the net difference between the carrying amount of Black Lake and the underlying equity of Black Lake, for all periods presented.

Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

Total Operating Revenues — Total operating revenues increased in 2008 compared to 2007, primarily due to changes in product mix and increased volumes.

Purchases of NGLs — Purchases of NGLs remained relatively constant in 2008 compared to 2007.

Segment Gross Margin — Segment gross margin increased in 2008 compared to 2007 primarily due to changes in product mix and increased volumes.

Operating and Maintenance Expense — Operating and maintenance expense remained relatively constant in 2008 compared to 2007.

Earnings from Equity Method Investments — Earnings from equity method investments increased in 2008 compared to 2007, primarily due to increased Black Lake throughput volumes.

Overall, our NGL pipelines experienced an increase in throughput volumes in 2008 compared to 2007, primarily as a result of an increase in drilling due to higher prices.

Liquidity and Capital Resources

Our predecessor’s sources of liquidity, prior to their acquisition by us, included cash generated from operations and funding from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s bank accounts and all cash disbursements were made from these accounts. Cash transactions for our predecessor were handled by DCP Midstream, LLC and were reflected in partners’ equity as intercompany advances from DCP Midstream, LLC.

We expect our sources of liquidity to include:

•

cash generated from operations;

•

cash distributions from our equity method investments;

•

borrowings under our revolving credit facility;

•

cash realized from the liquidation of securities that are pledged under our term loan facility;

•

issuance of additional partnership units; and

•

debt offerings.

We anticipate our more significant uses of resources to include:

•

capital expenditures;

•

contributions to our equity method investments to finance our share of their capital expenditures;

•

business and asset acquisitions;

•

collateral with counterparties to our swap contracts to secure potential exposure under these contracts; and

•

quarterly distributions to our unitholders.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months. Our commodity derivative program, as well as any future derivatives we enter into, may require us to post collateral, which at times may be significant, depending on commodity price movements.

The counterparties to each of our swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined “collateral threshold.” Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. As of May 2, 2008, we had letters of credit totaling $50.0 million, which reduces the amount of cash we may be required to post as collateral. As of May 2, 2008, we posted cash collateral with certain counterparties of approximately $12.2 million. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. Predetermined collateral thresholds for hedges guaranteed by DCP Midstream, LLC are generally dependent on DCP Midstream, LLC’s credit rating and the thresholds would be reduced to $0 in the event DCP Midstream, LLC’s credit rating were to fall below investment grade. DCP Midstream, LLC has provided guarantees to support certain natural gas and condensate hedging contracts through 2010 that were executed prior to our initial public offering.

Working Capital — Working capital is the amount by which current assets exceed current liabilities. Quarterly distributions, which are required under the terms of our partnership agreement based on Available Cash, as defined in the partnership agreement, reduce our working capital. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, along with other business factors that affect our net income and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, borrowings of and payments on debt, capital expenditures, and increases or decreases in restricted investments and other long-term assets.

We had working capital of $31.9 million as of March 31, 2008 and a working capital deficit of $1.1 million as of December 31, 2007. The changes in working capital are primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.

Cash Flow — Net cash provided by or used in operating, investing and financing activities were as follows:


	Three Months Ended March 31,
	2008			2007
	(Millions)
Net cash provided by operating activities	$	25.1		$	19.8
Net cash used in investing activities	$	(141.6	)	$	(15.7	)
Net cash provided by (used in) financing activities	$	145.1		$	(20.9	)

Net Cash Provided by Operating Activities — The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the condensed consolidated statements of cash flows and changes in working capital as discussed above.

We and our predecessor received cash distributions from equity method investments of $19.2 million and $5.6 million during the three months ended March 31, 2008 and 2007, respectively. Distributions exceeded earnings by $2.0 million for the three months ended March 31, 2008 and earnings exceeded distributions by $0.8 million for the three months ended March 31, 2007.

Net Cash Used in Investing Activities — Net cash used in investing activities during the three months ended March 31, 2008, was primarily used for: (1) capital expenditures of $9.2 million, which generally consisted of expenditures for construction and expansion of our infrastructure in addition to well connections and other upgrades to our existing facilities; (2) acquisition of the MEG subsidiaries of $10.9 million; (3) investments in Discovery of $1.9 million and East Texas of $0.9 million; and (4) net purchases of available-for-sale securities of $118.7 million. Net cash used in investing activities during the three months ended March 31, 2007 was primarily used for payment of an earnest deposit, capital expenditures, investments in Discovery and net purchases of available-for-sale securities.

We invested cash in equity method investments of $2.8 million and $2.4 million during the three months ended March 31, 2008 and 2007, respectively, of which $1.9 million and $2.4 million, respectively, was to fund our share of capital expansion projects, and $0.9 million in 2008 was to fund working capital needs.

Net Cash Provided by (Used in) Financing Activities — Net cash provided by financing activities during the three months ended March 31, 2008 was comprised of borrowings of $255.0 million, net proceeds from sales of common limited partner units of $132.3 million, contributions from non-controlling interests of $2.1 million and contributions from DCP Midstream, LLC of $1.9 million, partially offset by distributions to our unitholders of $15.7 million and to our general partner of $0.5 million and repayments of debt of $230.0 million. Net cash used in financing activities during the three months ended March 31, 2007 was primarily comprised of the excess of the purchase price over the acquired assets attributable to a payment related to our acquisition of our wholesale propane logistics business, changes in net parent advances and distributions to our unitholders.

We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 9 of the Notes to Condensed Consolidated Financial Statements in Item 1. “Financial Statements.”

Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:

•

maintenance capital expenditures, which are cash expenditures where we add on to or improve capital assets owned or acquire or construct new capital assets if such expenditures are made to maintain, including over the long term, our operating capacity or revenues; and

•

expansion capital expenditures, which are cash expenditures for acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets) in each case if such addition, improvement, acquisition or construction is made to increase our operating capacity or revenues.

Given our objective of growth through acquisitions, expansion of existing assets and other internal growth projects, we anticipate that we will continue to invest significant amounts of capital to grow. We actively consider a variety of assets for potential acquisition and expansion projects.

We have budgeted maintenance capital expenditures of $5.3 million and expansion capital expenditures of $2.9 million for the year ending December 31, 2008, excluding acquisitions. In addition, we anticipate maintenance capital expenditures of $2.7 million for our 25% interest in East Texas and $1.9 million for our 40% interest in Discovery for the year ending December 31, 2008. We also anticipate expansion capital expenditures of $3.0 million for our 25% interest in East Texas and $5.3 million for

our 40% interest in Discovery for the year ending December 31, 2008. We may be required to contribute cash to East Texas and Discovery to cover our respective share of expansion capital expenditures at both East Texas and Discovery. DCP Midstream, LLC has agreed to reimburse us for our share of Discovery’s capital expenditures for the Tahiti pipeline lateral. The board of directors may approve additional growth capital during the year, at their discretion.

Our capital expenditures, excluding acquisitions, totaled $9.2 million and $3.4 million, including maintenance capital expenditures of $0.8 million and $0.6 million, and expansion capital expenditures of $8.4 million and $2.8 million, during the three months ended March 31, 2008 and 2007, respectively. In conjunction with the acquisition of our investments in East Texas and Discovery, we entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for 25% of certain East Texas capital expenditures, and will reimburse us for 40% of certain Discovery capital expenditures, as defined in the agreement, from July 1, 2007 through completion of the capital projects, for a period not to exceed three years. We also have an agreement with certain producers whereby these producers will reimburse us for certain capital projects completed by us. As a result, during the three months ended March 31, 2008, we had an increase in receivables of $0.3 million related to collections of maintenance capital expenditures from DCP Midstream, LLC and producers. As a result, our total maintenance capital expenditures net of reimbursements were approximately $0.5 million for the three months ended March 31, 2008. For the three months ended March 31, 2007, our change in receivables and collections of maintenance capital expenditures from DCP Midstream, LLC and producers were not significant.

Annual maintenance capital expenditures in 2008 are expected to increase as a result of a larger asset base due to the MEG and Southern Oklahoma acquisitions. We expect to fund future capital expenditures with restricted investments, funds generated from our operations, borrowings under our credit facility and the issuance of additional partnership units.

Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders of $15.7 million during the three months ended March 31, 2008, as compared to $7.8 million for the same period in 2007. We intend to make quarterly distribution payments to our unitholders to the extent we have sufficient cash from operations after the establishment of reserves.

Description of Amended 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. The Credit Agreement matures on June 21, 2012. We have the option of increasing the size of the revolving credit facility to $1.0 billion with the consent of the issuing lenders. During the three months ended March 31, 2008, we borrowed $75.0 million from our revolving credit facility for general corporate purposes and $30.0 million to fund a partial retirement of our term loan facility, and we repaid $200.0 million. During the three months ended March 31, 2008, we borrowed $150.0 million from our term loan facility, and we repaid $30.0 million. As of March 31, 2008, the outstanding balance on the revolving credit facility was $435.0 million and the outstanding balance on the term loan facility was $220.0 million. As of March 31, 2008, the weighted-average effective interest rate on our revolving credit facility was 5.27% per annum, and the interest rate on our term loan facility was 2.88%.

Our obligations under the revolving credit facility are unsecured, and the term loan facility is secured at all times by high-grade securities, which are classified as restricted investments in the accompanying condensed consolidated balance sheets, in an amount equal to or greater than the outstanding principal amount of the term loan. Any portion of the term loan balance may be repaid at any time, and we would then have access to a corresponding amount of the collateral securities. Upon any prepayment of term loan borrowings, the amount of our revolving credit facility will automatically increase to the extent that the repayment of our term loan facility is made in connection with an acquisition of assets in the midstream energy business. The unused portion of the revolving credit facility may be used for general corporate purposes and for letters of credit. At March 31, 2008 and December 31, 2007, we had outstanding letters of credit of $25.3 million and $0.2 million under the Credit Agreement, respectively. As of March 31, 2008, the available capacity under our revolving credit facility was approximately $170.0 million.

Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of March 31, 2008, is as follows:


	Payments Due by Period
	Total		Remainder of 2008		2009-2010		2011-2012		2013 and Thereafter
	(Millions)
Long-term debt (a)	$	741.8	$	17.1	$	45.7	$	679.0	$	—
Operating lease obligations		41.1		6.5		15.0		12.0		7.6
Purchase obligations (b)		2.0		2.0		—		—		—
Other long-term liabilities (c)		8.4		—		0.7		0.2		7.5

Total	$	793.3	$	25.6	$	61.4	$	691.2	$	15.1

(a)

Includes interest payments on long-term debt that has been hedged, because the interest rate is determinable. Interest payments on long-term debt, which has not been hedged, are not included as they are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments.

(b)

Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(c)	Other long-term liabilities include $7.4 million of asset retirement obligations and $1.0 million of environmental reserves recognized in the March 31, 2008 condensed consolidated balance sheet.

Our off-balance obligations consist solely of our operating lease obligations.

Recent Accounting Pronouncements

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 results of operations, cash flows or financial position.

SFAS No. 157, “Fair Value Measurements,” or SFAS 157 — In September 2006, the FASB issued SFAS 157, which is 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;

•

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

The adoption of this standard resulted in us making slight changes to our valuation methodologies to incorporate 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 have recorded a cumulative effect transition adjustment of approximately $5.8 million as an increase to earnings and approximately $1.3 million as an increase to accumulated other comprehensive income during the three months ended March 31, 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.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in our 2007 Form 10-K.

Credit Risk

Our principal customers in the Natural Gas Services segment are large, natural gas marketing servicers and industrial end-users. Our principal customers in the Wholesale Propane Logistics segment are primarily retail propane distributors. In the NGL Logistics Segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Substantially all of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, as these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream, LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for exposure

in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with DCP Midstream, LLC’s credit policy. Our standard agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a satisfactory form.

Interest Rate Risk

Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

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, thereby reducing the exposure to market rate fluctuations. All interest rate swaps re-price prospectively approximately every 90 days. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. At March 31, 2008, the effective weighted-average interest rate on our $435.0 million of outstanding revolver debt was 5.27%, taking into account the $425.0 million of indebtedness with designated interest rate swaps.

Based on the annualized unhedged borrowings under our credit facility of $230.0 million as of March 31, 2008, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $1.2 million annualized increase or decrease in interest expense.

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, and sales activities. For gathering services, we receive fees or commodities from producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the types of contracts. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and futures.

Commodity Cash Flow Protection Activities — We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas and crude oil contracts to mitigate the effect pricing fluctuations may have on the value of our assets and operations.

We enter into derivative financial instruments to mitigate the risk of weakening natural gas, NGL and condensate prices associated with our percentage-of-proceeds arrangements and gathering operations. Because of the strong correlation between NGL prices and crude oil prices and the lack of liquidity in the NGL financial market, we typically use crude oil swaps to hedge NGL price risk. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2013.

The derivative financial instruments we have entered into are typically referred to as “swap” contracts. These swap contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow protection activities. We are using the mark-to-market method of accounting for all commodity derivative instruments, which has significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.

We estimate the following non-cash sensitivities related to the mark-to-market on our commodity derivatives associated with our Commodity Cash Flow Protection Activities:


	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market Impact (Decrease in Net Income)
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	6.5
Crude oil prices	$	5.00	Barrel	$	19.5

We estimate the following annualized sensitivities, excluding any impact from the mark-to-market on our commodity derivatives, due to the impact of market fluctuations in 2008:

	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	0.9
NGL prices	$	0.10	Gallon	$	2.9
Crude oil prices	$	5.00	Barrel	$	0.3

Based on our current contract mix, we believe that during the remainder of 2008 we will have a long position in natural gas, NGLs and condensate, and will be sensitive to changes in commodity prices.

These sensitivities include the effect of settlements on our financial derivatives. Please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities” in our 2007 Form 10-K for more information about our commodity price risk.

While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the correlation of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.

The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which has been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs, crude oil and natural gas have been extremely volatile.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, including the Chief Executive Officer and the Principal Accounting Officer, in the absence of a Chief Financial Officer, of DCP Midstream GP, LLC, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion and the required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. Our disclosure controls and procedures are effective in ensuring that information required to be disclosed in our reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and the Principal Accounting Officer, in the absence of a Chief Financial Officer, of DCP Midstream GP, LLC, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

The information required for this item is provided in Note 16, “Commitments and Contingent Liabilities,” included in Item 8 of our 2007 Form 10-K, which information is incorporated by reference into this item.

Item 1A.

Risk Factors

In addition to the other information set forth in this report, careful consideration should be given to the risk factors discussed in Part I, “Item 1A. Risk Factors” in our 2007 Form 10-K. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our 2007 Form 10-K. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our consolidated results of operations, financial condition and cash flows.

The following is a new or modified risk factor that should be read in conjunction with the risk factors disclosed in our 2007 Form 10-K:

Our derivative activities and the application of fair value measurements may have a material adverse effect on our earnings, profitability, cash flows, liquidity and financial condition.

We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas, NGL and condensate prices that we realize in our operations. To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have primarily entered into derivative financial instruments relating to the future price of crude oil. If the price relationship between NGLs and crude oil changes, our commodity price risk may increase. Furthermore, we have entered into derivative transactions related to only a portion of the volume of our expected natural gas supply and production of NGLs and condensate from our processing plants; as a result, we will continue to have direct commodity price risk to the open portion. Our actual future production may be significantly higher or lower than we estimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, reducing our liquidity.

We have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes from our gathering and processing operations through 2013 by entering into derivative financial instruments relating to the future price of natural gas and crude oil. Additionally, we have entered into interest rate swap agreements to convert a portion of the variable rate revolving debt under our Credit Agreement to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. The intent of these arrangements is to reduce the volatility in our cash flows resulting from fluctuations in commodity prices and interest rates.

We record all of our derivative financial instruments at fair value on our balance sheets primarily using information readily observable within the marketplace. In situations where market observable information is not available, we may use a variety of data points that are market observable, or in certain instances, develop our own expectation of fair value. We will continue to use market observable information as the basis for our fair value calculations, however, there is no assurance that such information will continue to be available in the future. In such instances we may be required to exercise a higher level of judgment in developing our own expectation of fair value, which may be significantly different from the historical fair values, and may increase the volatility of our earnings.

We will continue to evaluate whether to enter into any new derivative arrangements, but there can be no assurance that we will enter into any new derivative arrangement or that our future derivative arrangements will be on terms similar to our existing derivative arrangements. Although we enter into derivative instruments to mitigate our commodity price and interest rate risk, we also forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

The counterparties to our derivative instruments may require us to post collateral in the event that our potential payment exposure exceeds a predetermined collateral threshold. As of May 2, 2008, we posted cash collateral with certain counterparties of approximately $12.2 million. During the second quarter of 2008, we issued a $25.0 million letter of credit to a counterparty to our commodity derivative instruments, which reduces the cash collateral we are required to post. Depending on the movement in commodity prices, the amount of collateral posted may increase, reducing our liquidity.

As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our earnings and cash flows. In addition, even though our management monitors our derivative activities, these activities can result in material losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable derivative arrangement, the derivative arrangement is imperfect or ineffective, or our risk management policies and procedures are not properly followed or do not work as planned.

Item 6.

Exhibits

Exhibits


Exhibit Number		Description

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on May 9, 2008.


DCP Midstream Partners, LP

By:		DCP Midstream GP, LP
		its General Partner

By:		DCP Midstream GP, LLC
		its General Partner

By:		/s/ Mark A. Borer
		Name: Mark A. Borer
		Title: Chief Executive Officer

By:		/s/ Scott R. Delmoro
		Name: Scott R. Delmoro
		Title: Vice President & Controller,
		Chief Accounting Officer
		(Principal Accounting Officer)

EXHIBIT INDEX


Exhibit Number		Description

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Vice President & Controller, Chief Accounting Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.