DCP Midstream (DCP-PC) 10-Q 2010 Q1 Quarterly report

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, 2010

or

¨ 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    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 the definitions 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 Exchange Act).    Yes  ¨    No  x

As of May 6, 2010, there were outstanding 34,608,183 common units representing limited partner interests.

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2010

TABLE OF CONTENTS

Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements (unaudited):	1
	Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	2
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	4
	Condensed Consolidated Statements of Changes in Equity for the Three Months Ended March 31, 2010 and 2009	5
	Notes to the Condensed Consolidated Financial Statements	6
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
3.	Quantitative and Qualitative Disclosures about Market Risk	46
4.	Controls and Procedures	50
	PART II. OTHER INFORMATION
1.	Legal Proceedings	50
1A.	Risk Factors	50
6.	Exhibits	51
	Signatures	52
	Exhibit Index	53
	Certification of Chief Executive Officer Pursuant to Section 302
	Certification of Chief Financial Officer Pursuant to Section 302
	Certification of Chief Executive Officer Pursuant to Section 906
	Certification of Chief Financial Officer Pursuant to Section 906

i

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
MMBtu	one million British thermal units, a measurement of energy
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

ii

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, 2009, as well as the following risks and uncertainties:

• 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 and producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

• general economic, market and business conditions;

• the level and success of natural gas drilling around our assets, the level and quality of gas production volumes 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, inflation rates, 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, our ability to comply with the covenants to our credit agreement, and our ability to maintain our credit rating;

• 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 construction, 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 the operation of company owned and third-party-owned infrastructure;

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

• our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of the insurance to cover our losses;

• 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; and

• the amount of collateral we may be required to post from time to time in our transactions.

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, 2010			December 31, 2009
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	2.6		$	2.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.6 million and $0.5 million, respectively		59.6			78.7
Affiliates		60.9			73.8
Inventories		43.1			34.2
Unrealized gains on derivative instruments		6.9			7.3
Other		0.8			1.6
Total current assets		173.9			197.7
Restricted investments		—			10.0
Property, plant and equipment, net		1,017.0			1,000.1
Goodwill		92.1			92.1
Intangible assets, net		59.7			60.5
Investments in unconsolidated affiliates		113.5			114.6
Unrealized gains on derivative instruments		3.6			2.0
Other long-term assets		4.4			4.5
Total assets	$	1,464.2		$	1,481.5
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	67.8		$	85.5
Affiliates		52.1			43.1
Unrealized losses on derivative instruments		41.5			41.5
Accrued interest payable		0.7			0.7
Other		19.0			20.3
Total current liabilities		181.1			191.1
Long-term debt		615.0			613.0
Unrealized losses on derivative instruments		53.0			58.0
Other long-term liabilities		14.3			14.0
Total liabilities		863.4			876.1
Commitments and contingent liabilities
Equity:
Common unitholders (34,608,183 units issued and outstanding)		417.6			415.5
General partner unitholders		(5.8	)		(5.9	)
Accumulated other comprehensive loss		(33.5	)		(31.9	)
Total partners’ equity		378.3			377.7
Noncontrolling interests		222.5			227.7
Total equity		600.8			605.4
Total liabilities and equity	$	1,464.2		$	1,481.5

See accompanying notes to condensed consolidated financial statements.

1

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March  31,
	2010			2009
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	235.4		$	157.2
Sales of natural gas, propane, NGLs and condensate to affiliates		135.0			99.9
Transportation, processing and other		21.6			16.7
Transportation, processing and other to affiliates		5.7			3.6
Gains from commodity derivative activity, net		6.0			7.7
Losses from commodity derivative activity, net — affiliates		—			(0.7	)
Total operating revenues		403.7			284.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		191.5			137.8
Purchases of natural gas, propane and NGLs from affiliates		141.3			79.1
Operating and maintenance expense		19.0			16.2
Depreciation and amortization expense		17.8			14.6
General and administrative expense		3.7			3.2
General and administrative expense — affiliates		4.9			5.4
Total operating costs and expenses		378.2			256.3
Operating income		25.5			28.1
Interest income		—			0.2
Interest expense		(7.2	)		(7.3	)
Earnings (losses) from unconsolidated affiliates		7.9			(1.1	)
Income before income taxes		26.2			19.9
Income tax expense		(0.3	)		(0.1	)
Net income		25.9			19.8
Net (income) loss attributable to noncontrolling interests		(0.1	)		1.3
Net income attributable to partners		25.8			21.1
Net loss attributable to predecessor operations		—			1.0
General partner unitholders’ interest in net income		(3.8	)		(3.2	)
Net income allocable to limited partners	$	22.0		$	18.9
Net income per limited partner unit — basic and diluted	$	0.64		$	0.67
Weighted-average limited partner units outstanding — basic and diluted		34.6			28.2

See accompanying notes to condensed consolidated financial statements.

2

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March  31,
	2010			2009
	(Millions)
Net income	$	25.9		$	19.8
Other comprehensive loss:
Reclassification of cash flow hedge losses into earnings		6.0			4.5
Net unrealized losses on cash flow hedges		(7.6	)		(4.5	)
Total other comprehensive loss		(1.6	)		—
Total comprehensive income		24.3			19.8
Total comprehensive (income) loss attributable to noncontrolling interests		(0.1	)		1.3
Total comprehensive income attributable to partners	$	24.2		$	21.1

See accompanying notes to condensed consolidated financial statements.

3

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2010			2009
	(Millions)
OPERATING ACTIVITIES:
Net income	$	25.9		$	19.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		17.8			14.6
(Earnings) losses from unconsolidated affiliates		(7.9	)		1.1
Distributions from unconsolidated affiliates		9.8			0.5
Other, net		0.5			0.5
Change in operating assets and liabilities, which provided (used) cash net of effects of acquisitions:
Accounts receivable		31.9			14.0
Inventories		(8.9	)		2.9
Net unrealized gains on derivative instruments		(7.8	)		(0.2	)
Accounts payable		(9.3	)		(20.2	)
Accrued interest		—			(0.4	)
Other current assets and liabilities		(0.9	)		(2.5	)
Other long-term assets and liabilities		(0.1	)		0.4
Net cash provided by operating activities		51.0			30.5
INVESTING ACTIVITIES:
Capital expenditures		(12.2	)		(55.9	)
Acquisitions, net of cash acquired		(22.0	)		(0.3	)
Investments in unconsolidated affiliates		(0.7	)		(0.2	)
Proceeds from sale of assets		0.2			—
Purchases of available-for-sale securities		—			(1.0	)
Proceeds from sales of available-for-sale securities		10.1			0.8
Net cash used in investing activities		(24.6	)		(56.6	)
FINANCING ACTIVITIES:
Proceeds from debt		116.6			—
Payments of debt		(114.6	)		(11.5	)
Net change in advances to predecessor from DCP Midstream, LLC		—			3.0
Distributions to unitholders and general partner		(24.6	)		(20.1	)
Distributions to noncontrolling interests		(3.7	)		(3.9	)
Contributions from noncontrolling interests		3.9			8.7
Purchase of additional interest in a subsidiary		(3.5	)		—
Net cash used in financing activities		(25.9	)		(23.8	)
Net change in cash and cash equivalents		0.5			(49.9	)
Cash and cash equivalents, beginning of period		2.1			61.9
Cash and cash equivalents, end of period	$	2.6		$	12.0

See accompanying notes to condensed consolidated financial statements.

4

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Partners’ Equity
	Predecessor Equity			Common Unitholders			Subordinated Unitholders			General Partner Unitholders			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2010	$	—		$	415.5		$	—		$	(5.9	)	$	(31.9	)	$	227.7		$	605.4
Purchase of additional interest in a subsidiary		—			1.0			—			—			—			(5.5	)		(4.5	)
Distributions		—			(20.8	)		—			(3.8	)		—			(3.7	)		(28.3	)
Contributions		—			—			—			—			—			3.9			3.9
Comprehensive income (loss):
Net income		—			21.9			—			3.9			—			0.1			25.9
Reclassification of cash flow hedge losses into earnings		—			—			—			—			6.0			—			6.0
Net unrealized losses on cash flow hedges		—			—			—			—			(7.6	)		—			(7.6	)
Total comprehensive income (loss)		—			21.9			—			3.9			(1.6	)		0.1			24.3
Balance, March 31, 2010	$	—		$	417.6		$	—		$	(5.8	)	$	(33.5	)	$	222.5		$	600.8
Balance, January 1, 2009	$	66.0		$	429.0		$	(54.6	)	$	(4.8	)	$	(40.5	)	$	167.7		$	562.8
Net change in parent advances		3.0			—			—			—			—			—			3.0
Distributions		—			(14.8	)		(2.1	)		(3.2	)		—			(3.9	)		(24.0	)
Conversion of subordinated units to common units		—			(52.1	)		52.1			—			—			—			—
Contributions		—			—			—			—			—			8.7			8.7
Comprehensive income (loss):
Net loss attributable to predecessor operations		(1.0	)		—			—			—			—			—			(1.0	)
Net income (loss)		—			14.3			4.6			3.2			—			(1.3	)		20.8
Reclassification of cash flow hedge losses into earnings		—			—			—			—			4.5			—			4.5
Net unrealized losses on cash flow hedges		—			—			—			—			(4.5	)		—			(4.5	)
Total comprehensive (loss) income		(1.0	)		14.3			4.6			3.2			—			(1.3	)		19.8
Balance, March 31, 2009	$	68.0		$	376.4		$	—		$	(4.8	)	$	(40.5	)	$	171.2		$	570.3

See accompanying notes to condensed consolidated financial statements.

5

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 limited partnership that was formed in August 2005. We completed our initial public offering on December 7, 2005. Our partnership includes: our Northern Louisiana system; our Southern Oklahoma system; our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system and a 75% interest in our Colorado system (of which 5% was acquired in February 2010); our 50.1% interest in our East Texas system (of which 25.1% was acquired in April 2009); our Michigan systems (of which certain assets were acquired in November 2009); our wholesale propane logistics business; and our NGL transportation pipelines (which includes our Wattenberg pipeline acquired in January 2010).

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, and 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 35% of our partnership.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control and undivided interests in jointly owned assets. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

The condensed consolidated financial statements include our accounts, which have been combined with the historical assets, liabilities and operations of our predecessor operations. We refer to the assets, liabilities and operations of DCP East Texas Holdings, LLC, or East Texas, prior to our acquisition of an additional 25.1% limited liability company interest from DCP Midstream, LLC in April 2009, collectively as our “predecessor.” Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas, we owned a 25.0% limited liability company interest in East Texas which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability company interest in East Texas, and account for East Texas as a consolidated subsidiary.This transaction was 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, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method; accordingly our financial information includes the historical results of East Texas for all periods presented. The amount of the purchase price in excess, or in deficit of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to, or an increase to partners’ equity, respectively. In addition, the results of operations of our Michigan systems and our Wattenberg pipeline have been included in the condensed consolidated financial statements since their respective acquisition dates.

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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. 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 intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates.

6

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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. Results of operations for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. 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 2009 Form 10-K.

Certain amounts in the prior period condensed consolidated financial statements have been reclassified to the current period presentation.

2. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,”or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended the Accounting Standards Codification, or ASC, Topic 820-10 “Fair Value Measurement and Disclosures—Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,”or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our condensed financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,”or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

3. Acquisitions

Gathering, Compression, Transportation and Processing Assets

On February 3, 2010 we acquired an additional 5% interest in Collbran Valley Gas Gathering LLC, or Collbran, from Delta Petroleum Company, or Delta, for $3.5 million in cash, bringing our total ownership in Collbran to 75%. We may pay an additional $2.0 million of contingent consideration to Delta, depending on volumes Delta delivers, by June 30, 2011, pursuant to a processing agreement. As of March 31, 2010, we have recognized the fair value of this contingent consideration of approximately $1.0 million, which we have recorded to other current liabilities in our condensed consolidated balance sheet. In addition, as part of this transaction we assumed Delta’s unpaid capital calls to Collbran of $2.4 million, which have been paid as of March 31, 2010. Accordingly we have recognized a $5.5 million reduction in noncontrolling interest in equity, which represents the carrying value of Delta’s 5% interest in Collbran, and an increase of $1.0 million to common unitholders in equity, which represents the difference between the fair value of the consideration and the carrying value of Delta’s 5% interest.

7

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

On January 28, 2010 we acquired an interstate natural gas liquids pipeline, or the Wattenberg pipeline, from Buckeye Partners, L.P., for $22.0 million in cash, funded with borrowings under our revolving credit facility. This transaction was accounted for as a business combination. The 350-mile pipeline originates in the Denver-Julesburg, or DJ Basin, in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. The results of the asset are included in our NGL Logistics segment prospectively, from the date of acquisition. The purchase price was allocated to property, plant and equipment.

On April 1, 2009, we acquired an additional 25.1% interest in East Texas, and a fixed price natural gas liquids derivative by NGL component for the period of April 2009 to March 2010, or NGL Hedge, from DCP Midstream, LLC, for aggregate consideration of 3,500,000 Class D units, valued at $49.7 million. This transaction was among entities under common control. Prior to this transaction we owned a 25.0% interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% interest in East Texas, and account for East Texas as a consolidated subsidiary.

Combined Financial Information

The following table presents the impact on the condensed consolidated statements of operations, adjusted for the acquisition of an additional 25.1% interest in East Texas, from DCP Midstream, LLC, for the three months ended March 31, 2009.

Three Months Ended March 31, 2009

	DCP Midstream Partners,  LP (As previously reported)			Consolidate East Texas			Remove East Texas Equity Losses		Combined DCP Midstream Partners, LP
	(a)			(b)			(c)
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	217.7		$	39.4		$	—	$	257.1
Transportation, processing and other		15.9			4.4			—		20.3
Gains from commodity derivative activity, net		7.0			—			—		7.0
Total operating revenues		240.6			43.8			—		284.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		182.8			34.1			—		216.9
Operating and maintenance expense		9.2			7.0			—		16.2
Depreciation and amortization expense		10.4			4.2			—		14.6
General and administrative expense		5.8			2.8			—		8.6
Total operating costs and expenses		208.2			48.1			—		256.3
Operating income (loss)		32.4			(4.3	)		—		28.1
Interest expense, net		(7.1	)		—			—		(7.1	)
Losses from unconsolidated affiliates		(2.2	)		—			1.1		(1.1	)
Income (loss) before income taxes		23.1			(4.3	)		1.1		19.9
Income tax expense		(0.1	)		—			—		(0.1	)
Net income (loss)		23.0			(4.3	)		1.1		19.8
Net (income) loss attributable to noncontrolling interests		(0.9	)		2.2			—		1.3
Net income (loss) attributable to partners	$	22.1		$	(2.1	)	$	1.1	$	21.1

(a) Amounts as previously reported with 25% of East Texas’ results presented as losses from unconsolidated affiliates.

(b) Adjustments to present East Texas on a consolidated basis at 100%, with noncontrolling interest of 49.9%.

(c) Adjustments to remove East Texas equity losses at 25%.

The following table presents unaudited pro forma information for the condensed consolidated statements of operations for the three months ended March 31, 2010 and 2009, as if the acquisition of the Wattenberg pipeline had occurred at the beginning of each period presented. Revenues of $0.6 million and net income attributable to partners of $0.3 million, associated with the acquired assets, from the date of acquisition through March 31, 2010 have been included in the Condensed Consolidated Statement of Operations.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Three Months Ended March 31, 2010								Three Months Ended March 31, 2009
	DCP Midstream Partners, LP			Acquisition of the Wattenberg Pipeline		DCP Midstream Partners, LP Pro Forma			DCP Midstream Partners, LP			Acquisition of the Wattenberg Pipeline			DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	403.7		$	0.2	$	403.9		$	284.4		$	3.3	$287.7
Net income attributable to partners	$	25.8		$	0.1	$	25.9		$	21.1		$	2.0	$23.1
Less:
Net loss attributable to predecessor operations		—			—		—			1.0			—	1.0
General partner unitholders interest in net income		(3.8	)		—		(3.8	)		(3.2	)		—	(3.2)
Net income allocable to limited partners	$	22.0		$	0.1	$	22.1		$	18.9		$	2.0	$20.9
Net income per limited partner unit – basic and diluted	$	0.64		$	—	$	0.64		$	0.67		$	0.07	$0.74

The pro forma information is not intended to reflect actual results that would have occurred if the assets had been combined during the periods presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Omnibus Agreement and Other General and Administrative Charges

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 incurred $2.5 million and $2.4 million, respectively, for the three months ended March 31, 2010 and 2009, for all fees under the Omnibus Agreement.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. During the three months ended March 31, 2010 and 2009 East Texas incurred $2.0 million and $2.2 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

Outside of the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC of $0.3 million and $0.7 million for the three months ended March 31, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

Other Agreements and Transactions with DCP Midstream, LLC

In conjunction with our acquisition of the Wattenberg pipeline, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement is effective through November 2010, renewing on an evergreen basis thereafter. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

In conjunction with our acquisition of a 50.1% limited liability company interest in East Texas from DCP Midstream, LLC, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain amounts of East Texas capital projects as defined in the Contribution Agreements. These reimbursements are for a period not to exceed three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $3.8 million and $10.9 million for the three months ended March 31, 2010 and 2009, respectively.

On February 11, 2009, our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, was temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. We are actively pursuing full reimbursement of our costs and lost margin associated with the incident from the responsible third party and East Texas filed a lawsuit in December 2009 to recover damages from the responsible third party. In the event we are unable to recover our costs and lost margin from the responsible third party, we have insurance covering property damage, net of applicable deductibles. Following this incident, DCP Midstream, LLC has agreed to reimburse to us twenty-five percent of any claims received as reimbursement of costs and lost margin, from the responsible third party or from insurance. DCP Midstream, LLC will pay seventy-five percent of costs related to the incident as a result of this agreement.

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

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system, which is part of our Natural Gas Services segment, that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under a firm transportation agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand and volumes supplying an industrial end user are sold to DCP Midstream, LLC at an index-based price, less contractually agreed to marketing fees. Revenues associated with these activities are reported gross in our condensed consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the transportation agreements. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

In April 2009, we entered into a thirteen year contractual arrangement with DCP Midstream, LLC in which we pay DCP Midstream, LLC a fee for processing services associated with the gas we gather on our Lindsay system, which is part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from our Lindsay system being processed at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the condensed consolidated statements of operations as purchases of natural gas, propane, NGLs and condensate from affiliates. In addition, as part of this arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

DCP Midstream, LLC has issued parental guarantees, totaling $103.0 million as of March 31, 2010, in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC interest of 0.5% per annum on $60.0 million of these outstanding guarantees.

DCP Midstream, LLC was a significant customer during the three months ended March 31, 2010 and 2009.

Spectra Energy

We entered into a propane supply agreement with Spectra Energy, effective May 1, 2008 and terminating April 30, 2014, which provides us propane supply at our marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

ConocoPhillips

We have multiple agreements with ConocoPhillips and its affiliates. The agreements include fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $0 and $0.2 million of capital reimbursements during the three months ended March 31, 2010 and 2009, respectively.

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:

	Three Months Ended March  31,
	2010		2009
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	133.6	$	99.8
Transportation, processing and other	$	3.8	$	1.2
Purchases of natural gas, propane and NGLs	$	62.8	$	43.1
Losses from commodity derivative activity, net	$	—	$	(0.7	)
General and administrative expense	$	4.8	$	5.3
Interest expense	$	0.1	$	0.1
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	74.1	$	33.7
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	1.4	$	0.1
Transportation, processing and other	$	1.9	$	2.4
Purchases of natural gas, propane and NGLs	$	2.0	$	1.9
General and administrative expense	$	0.1	$	0.1
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	2.4	$	0.4

We had balances with affiliates as follows:

	March 31, 2010			December 31, 2009
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	58.1		$	71.5
Accounts payable	$	25.3		$	24.4
Unrealized gains on derivative instruments—current	$	4.0		$	5.5
Unrealized losses on derivative instruments—current	$	(3.8	)	$	(5.4	)
Spectra Energy:
Accounts receivable	$	0.7		$	0.1
Accounts payable	$	23.8		$	16.6
ConocoPhillips:
Accounts receivable	$	2.1		$	2.2
Accounts payable	$	0.6		$	2.1
Unconsolidated affiliates:
Accounts payable	$	2.4		$	—

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

5. Property, Plant and Equipment

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

	Depreciable Life	March 31, 2010			December 31, 2009
		(Millions)
Gathering systems	15 — 30 Years	$	687.7		$	683.0
Processing plants	25 — 30 Years		431.8			427.4
Terminals	25 — 30 Years		29.0			28.9
Transportation	25 — 30 Years		239.1			217.2
General plant	3 — 5 Years		15.6			15.2
Other	20 — 50 Years		0.1			0.1
Construction work in progress			24.2			21.8
Property, plant and equipment			1,427.5			1,393.6
Accumulated depreciation			(410.5	)		(393.5	)
Property, plant and equipment, net		$	1,017.0		$	1,000.1

The above amounts include accrued capital expenditures of $3.2 million and $3.8 million as of March 31, 2010 and December 31, 2009, respectively, which are included in other current liabilities in the condensed consolidated balance sheets. Interest capitalized on construction projects for the three months ended March 31, 2010 was $0 and for the year ended December 31, 2009 was $1.3 million.

Depreciation expense was $17.0 million and $14.0 million for the three months ended March 31, 2010 and 2009, respectively.

6. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

	Percentage of Ownership as of March 31, 2010  and December 31, 2009		Carrying Value as of
			March 31, 2010		December 31, 2009
			(Millions)
Discovery Producer Services LLC	40	%	$	106.9	$	108.2
Black Lake Pipe Line Company	45	%		6.4		6.2
Other	50	%		0.2		0.2
Total investments in unconsolidated affiliates			$	113.5	$	114.6

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $37.0 million and $37.6 million at March 31, 2010 and December 31, 2009, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $5.6 million and $5.7 million at March 31, 2010 and December 31, 2009, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Earnings (losses) from investments in unconsolidated affiliates were as follows:

	Three Months Ended March  31,
	2010		2009
	(Millions)
Discovery Producer Services LLC	$	7.4	$	(1.5	)
Black Lake Pipe Line Company and other		0.5		0.4
Total earnings (losses) from unconsolidated affiliates	$	7.9	$	(1.1	)

The following summarizes financial information of our investments in unconsolidated affiliates:

	Three Months Ended March  31,
	2010		2009
	(Millions)
Statements of operations:
Operating revenue	$	61.6	$	21.5
Operating expenses	$	43.5	$	25.9
Net income (loss)	$	18.0	$	(4.6	)

	March 31, 2010			December 31, 2009
	(Millions)
Balance sheets:
Current assets	$	41.9		$	41.8
Long-term assets		380.2			383.8
Current liabilities		(18.1	)		(17.4	)
Long-term liabilities		(24.0	)		(23.6	)
Net assets	$	380.0		$	384.6

13

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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. If 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 as well as any letters of credit that they have provided.

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

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

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

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market 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 9 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 foridentical assets or liabilities in active markets.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

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

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

Commodity Derivative Assets and Liabilities

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

Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

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 an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

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

Interest Rate Derivative Assets and Liabilities

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

15

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Short-Term and Restricted Investments

We are required to post collateral to secure the term loan portion of our credit facility, and may elect to invest a portion of our available cash and restricted investment balances in various financial instruments such as commercial paper and money market instruments. The money market instruments are generally priced at acquisition cost, plus accreted interest at the stated rate, which approximates fair value, without any additional adjustments. Given that there is no observable exchange traded market for identical money market securities, we have classified these instruments within Level 2. Investments in commercial paper are priced using a yield curve for similarly rated instruments, and are classified within Level 2. As of March 31, 2010, we held no short-term or restricted investments.

Nonfinancial Assets and Liabilities

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

The following table presents the financial instruments carried at fair value as of March 31, 2010 and December 31, 2009, by consolidated balance sheet caption and by valuation hierarchy as described above:

	March 31, 2010											December 31, 2009
	Level 1		Level 2			Level 3			Total Carrying Value			Level 1		Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets:
Short term investments (a)	$	—	$	—		$	—		$	—		$	—	$	0.1		$	—		$	0.1
Commodity derivatives (b)	$	—	$	5.4		$	1.5		$	6.9		$	—	$	6.9		$	0.4		$	7.3
Long-term assets:
Restricted investments	$	—	$	—		$	—		$	—		$	—	$	10.0		$	—		$	10.0
Commodity derivatives (c)	$	—	$	2.4		$	1.2		$	3.6		$	—	$	1.8		$	0.2		$	2.0
Current liabilities (d):
Commodity derivatives	$	—	$	(20.7	)	$	(0.3	)	$	(21.0	)	$	—	$	(20.3	)	$	(0.8	)	$	(21.1	)
Interest rate derivatives	$	—	$	(20.5	)	$	—		$	(20.5	)	$	—	$	(20.4	)	$	—		$	(20.4	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(39.1	)	$	(0.4	)	$	(39.5	)	$	—	$	(46.0	)	$	(0.4	)	$	(46.4	)
Interest rate derivatives	$	—	$	(13.5	)	$	—		$	(13.5	)	$	—	$	(11.6	)	$	—		$	(11.6	)

(a) Included in other current assets in our condensed consolidated balance sheets.

(b) Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.

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

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

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

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Changes in Level 3 Fair Value Measurements

The tables below illustrate 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 were a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into Level 3” and “Transfers out of Level 3” captions.

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.

	Commodity Derivative Instruments
	Current Assets			Long-Term Assets		Current Liabilities			Long-Term Liabilities
	(Millions)
Three months ended March 31, 2010:
Beginning balance	$	0.4		$	0.2	$	(0.8	)	$	(0.4	)
Net realized and unrealized gains (losses) included in earnings		1.2			1.0		(0.1	)		—
Transfers into Level 3 (a)		—			—		—			—
Transfers out of Level 3 (a)		—			—		—			—
Purchases, Issuances and Settlements net		(0.1	)		—		0.6			—
Ending balance	$	1.5		$	1.2	$	(0.3	)	$	(0.4	)
Net unrealized gains still held included in earnings (b)	$	1.2		$	1.0	$	0.4		$	—
Three months ended March 31, 2009:
Beginning balance	$	0.3		$	1.7	$	—		$	—
Net realized and unrealized gains (losses) included in earnings		0.8			—		—			(0.3	)
Net transfers in (out) of Level 3 (c)		—			—		—			—
Purchases, Issuances and Settlements net		(0.1	)		—		—			—
Ending balance	$	1.0		$	1.7	$	—		$	(0.3	)
Net unrealized gains (losses) still held included in earnings (b)	$	0.8		$	—	$	—		$	(0.3	)

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

(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of March 31, 2010 and 2009.

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

17

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

During the three months ended March 31, 2010, we had no significant transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.

Estimated Fair Value of Financial Instruments

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on derivative instruments are carried at fair value. The carrying and fair values of outstanding balances under our credit agreement are $615.0 million, and $593.9 million, respectively, as of March 31, 2010 and $613.0 million and $590.0 million, respectively, as of December 31, 2009. We determine the fair value of our credit facility borrowings based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. Additionally, we have executed interest rate swap agreements on a portion of our interest rate exposure which swaps variable for fixed interest rates.

8. Debt

Long-term debt was as follows:

	March 31, 2010		December 31, 2009
	(Millions)
Revolving credit facility, weighted-average variable interest rate of 0.70% and 0.69%, respectively, and net effective interest rate of 4.33% and 4.41%, respectively, due June 21, 2012 (a)	$	615.0	$	603.0
Term loan facility, variable interest rate of 0.34%, due June 21, 2012 (b)		—		10.0
Total long-term debt	$	615.0	$	613.0

(a) $575.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%, for a net effective rate of 4.33% on the $615.0 million of outstanding debt under our revolving credit facility as of March 31, 2010.

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

Credit Agreement

We have an $824.6 million revolving credit facility that matures June 21, 2012, or the Credit Agreement.

At March 31, 2010 and December 31, 2009, we had $0.3 million of letters of credit issued under the Credit Agreement outstanding. As of December 31, 2009 we had outstanding term loan balances under the Credit Agreement, which were fully collateralized by investments in high-grade securities, classified as restricted investments in the accompanying condensed consolidated balance sheets as of December 31, 2009. As of March 31, 2010 the available capacity under the revolving credit facility was $209.3 million, which is net of non-participation by Lehman Brothers Commercial Bank.

18

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0. Prior to our credit rating that we received on December 7, 2009 from Standard & Poor’s Ratings Group, the Credit Agreement also required us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as is defined by the Credit Agreement) of equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. As a result of our credit rating, we are no longer required to maintain this interest coverage ratio.

Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, amounts borrowed under our credit facility will not mature prior to the June 21, 2012 maturity date.

Other Agreements

As of March 31, 2010, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million, which reduces the amount of cash we may be required to post as collateral. We pay a fee of 0.75% per annum on this letter of credit. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

9. Risk Management and Hedging Activities

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

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering and processing services, we may receive fees or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2015 with natural gas and crude oil derivative instruments, including derivative instruments entered into subsequent to the balance sheet date. Additionally, given the limited depth of the NGL derivatives market, we primarily utilize crude oil swaps to mitigate a portion of our commodity price exposure for propane and heavier NGLs. Historically, prices of NGLs have been generally related to the price of crude oil, with some exceptions, notably in late 2008 to early 2009, when NGL pricing was at a greater discount to crude oil. Given the relationship and the lack of liquidity in the NGL financial market, we have historically used crude oil swaps to mitigate a portion of NGL price risks. When the relationship of NGL prices to crude oil prices is outside of historical ranges, we experience additional exposure as a result of the relationship. These transactions are primarily accomplished through the use of forward contracts, which are swap futures that effectively exchange our floating rate price risk for a fixed rate. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.

With respect to our Pelico system, we may enter into financial derivatives to lock in transportation margins across the system, or to lock in margins around our leased storage facility to maximize value. This objective may be achieved through the use of physical purchases or sales of gas that are accounted for under accrual accounting. While the physical purchase or sale of gas transactions are accounted for under accrual accounting and any inventory is stated at lower of cost or market, the swaps are not designated as hedging instruments for accounting purposes and any change in fair value of these instruments is reflected within our condensed consolidated statements of operations.

19

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Our Wholesale Propane Logistics segment is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and the change in value is reflected in the current period within our condensed consolidated statements of operations as a gain or loss on commodity derivative activity.

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.

Commodity Cash Flow Hedges — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives that manage our commodity price risk. Prior to July 1, 2007, we used NGL, natural gas and crude oil swaps to mitigate a portion of the risk of market fluctuations in the price of NGLs, natural gas and condensate. Given our election to discontinue using the hedge method of accounting, the remaining net losses deferred in AOCI relative to cash flow hedges are reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings.

Interest Rate Risk

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

Contingent Credit Features

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

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

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

20

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

• Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our credit agreement. As of March 31, 2010, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

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

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position.

As of March 31, 2010, we had $56.8 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of March 31, 2010 if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of March 31, 2010, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $52.3 million.

As of March 31, 2010 our interest rate swaps were in a net liability position of approximately $34.0 million, of which, the entire amount is subject to credit-risk related contingent features. If we were to have a default of any of our covenants to our credit agreement, that occurs and is continuing, the counterparties to our swap instruments may have the right to request that we net settle the instrument in the form of cash.

Collateral

As of March 31, 2010, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million and DCP Midstream, LLC had issued and outstanding parental guarantees totaling $103.0 million in favor of certain counterparties to our commodity derivative instruments. This letter of credit and the parental guarantees reduce the amount of cash we may be required to post as collateral. As of March 31, 2010, we had no cash collateral posted with counterparties to our commodity derivative instruments.

Summarized Derivative Information

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

	March 31, 2010			December 31, 2009
	(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(0.4	)	$	(0.8	)
Interest rate cash flow hedges:
Net deferred losses in AOCI		(33.1	)		(31.1	)
Total AOCI	$	(33.5	)	$	(31.9	)

21

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

Balance Sheet Line Item	March 31, 2010		December 31, 2009		Balance Sheet Line Item	March 31, 2010			December 31, 2009
	(Millions)					(Millions)
Derivative Assets Designated as Hedging Instruments:					Derivative Liabilities Designated as Hedging Instruments:
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments – current	$	—	$	—	Unrealized losses on derivative instruments – current	$	(20.5	)	$	(20.4	)
Unrealized gains on derivative instruments – long term		—		—	Unrealized losses on derivative instruments – long term		(13.5	)		(11.6	)
	$	—	$	—		$	(34.0	)	$	(32.0	)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments – current	$	6.9	$	7.3	Unrealized losses on derivative instruments – current	$	(21.0	)	$	(21.1	)
Unrealized gains on derivative instruments – long term		3.6		2.0	Unrealized losses on derivative instruments – long term		(39.5	)		(46.4	)
	$	10.5	$	9.3		$	(60.5	)	$	(67.5	)

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

	Gain (Loss) Recognized in AOCI on Derivatives — Effective Portion						Gain (Loss) Reclassified From AOCI to Earnings — Effective Portion						Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing					Deferred Losses in AOCI Expected to be Reclassified into Earnings Over the Next 12 Months
	Three Months Ended March 31,
	2010			2009			2010			2009			2010		2009
	(Millions)						(Millions)						(Millions)					(Millions)
Interest rate derivatives	$	(7.6	)	$	(4.5	)	$	(5.6	)	$	(4.0	)(a)	$	—	$	—	(a)(c)	$	(19.7	)
Commodity derivatives	$	—		$	—		$	(0.4	)	$	(0.5	)(b)	$	—	$	—	(b)(c)	$	(0.2	)

(a) Included in interest expense in our condensed consolidated statements of operations.

(b) Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.

(c) For the three months ended March 31, 2010 and 2009, 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.

22

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the condensed consolidated statements of operations. The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected:

Commodity Derivatives: Statements of Operations Line Item	Three Months Ended March 31,
	2010			2009
	(Millions)
Third party:
Realized	$	(2.1	)	$	6.9
Unrealized		8.1			0.8
Gains from commodity derivative activity, net	$	6.0		$	7.7
Affiliates:
Realized	$	(0.1	)	$	(0.7	)
Unrealized		0.1			—
Losses from commodity derivative activity, net — affiliates	$	—		$	(0.7	)

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

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

	March 31, 2010
	Crude Oil		Natural Gas		Natural Gas Liquids
Year of Expiration	Net Long (Short) Position (Bbls)		Net Long (Short) Position (MMBtu)		Net Long (Short) Position (Bbls)
2010	(732,875	)	(1,840,000	)	(440,000	)
2011	(949,000	)	(1,496,500	)	—
2012	(777,750	)	(1,500,600	)	—
2013	(748,250	)	(730,000	)	—
2014	(365,000	)	—		—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of March 31, 2010 we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange $575.0 million of our floating rate obligation to a fixed rate obligation through June 2012.

10. 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 as defined below, to unitholders of record on the applicable record date, as determined by our general partner.

In November 2009, we issued 2,500,000 common units at $25.40 per unit, and in December 2009 we issued an additional 375,000 common units to the underwriters who exercised their overallotment option. We received proceeds of $69.5 million, net of offering costs.

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP LP Holdings, LP and DCP Midstream GP, LP in consideration for an additional 25.1% interest in East Texas and the NGL Hedge. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

23

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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; and

• 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— The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1% as of March 31, 2010. 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 incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common limited partner unit issuances, 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 theDistributions of Available Cash after the Subordination Period section below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Class D Units— All of the Class D units were held by DCP Midstream, LLC and converted into our common units on a one for one basis on August 17, 2009. The holders of the Class D units received the distribution for the second quarter of 2009, paid on August 14, 2009.

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

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, which ended in February 2009, 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.

24

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The following table presents our cash distributions paid in 2010 and 2009:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
February 12, 2010	$	0.600	$	24.6
November 13, 2009		0.600		22.6
August 14, 2009		0.600		22.6
May 15, 2009		0.600		20.1
February 13, 2009		0.600		20.1

11. Commitments and Contingent Liabilities

Litigation— We are a party to various legal proceedings, as well as administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our condensed consolidated results of operations, financial position, or cash flows. See Note 17 in Item 8 of our 2009 Form 10-K for additional details.

El Paso — On February 27, 2009, a jury in the District Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, L.P., or El Paso, and against one of our subsidiaries and DCP Midstream, LLC. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000. During the second quarter of 2009 we filed an appeal in the 14th Court of Appeals, Texas. El Paso filed an additional lawsuit in the District Court of Webster Parish, Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the Minden processing plant. The Louisiana court determined in August 2009 that El Paso’s Louisiana claims were barred by the doctrine of res judicata and dismissed the case with prejudice in Louisiana. In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso regarding this matter in Texas and Louisiana. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement, which is within the amount of our previously disclosed contingent liability. The cases have been dismissed in both Texas and Louisiana.

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

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

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 2009 Form 10-K for additional details.

25

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

12. 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) our Northern Louisiana system; (2) our Southern Oklahoma system; (3) our 40% limited liability company interest in Discovery; (4) our 75% interest in our Colorado system; (5) our Wyoming system; (6) our 50.1% interest in our East Texas system; and (7) our Michigan systems.

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

NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, the Wattenberg NGL transportation pipeline, 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:

Three Months Ended March 31, 2010

	Natural  Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
							(Millions)
Total operating revenue	$	218.1		$	180.8		$	4.8		$	—		$	403.7
Gross margin (a)	$	53.8		$	13.7		$	3.4		$	—		$	70.9
Operating and maintenance expense		(16.2	)		(2.6	)		(0.2	)		—			(19.0	)
Depreciation and amortization expense		(17.0	)		(0.3	)		(0.5	)		—			(17.8	)
General and administrative expense		—			—			—			(8.6	)		(8.6	)
Earnings from unconsolidated affiliates		7.4			—			0.5			—			7.9
Interest expense		—			—			—			(7.2	)		(7.2	)
Income tax expense (b)		—			—			—			(0.3	)		(0.3	)
Net income (loss)		28.0			10.8			3.2			(16.1	)		25.9
Net income attributable to noncontrolling interests		(0.1	)		—			—			—			(0.1	)
Net income (loss) attributable to partners	$	27.9		$	10.8		$	3.2		$	(16.1	)	$	25.8
Non-cash derivative mark-to-market (c)	$	8.4		$	(0.6	)	$	—		$	—		$	7.8
Capital expenditures	$	12.1		$	—		$	0.1		$	—		$	12.2
Acquisition expenditures	$	—		$	—		$	22.0		$	—		$	22.0
Investments in unconsolidated affiliates	$	0.7		$	—		$	—		$	—		$	0.7

26

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Three Months Ended March 31, 2009

	Natural  Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
							(Millions)
Total operating revenue	$	149.8		$	132.8		$	1.8		$	—		$	284.4
Gross margin (a)	$	40.4		$	25.8		$	1.3		$	—		$	67.5
Operating and maintenance expense		(13.2	)		(2.7	)		(0.3	)		—			(16.2	)
Depreciation and amortization expense		(13.9	)		(0.3	)		(0.4	)		—			(14.6	)
General and administrative expense		—			—			—			(8.6	)		(8.6	)
(Losses) earnings from unconsolidated affiliates		(1.5	)		—			0.4			—			(1.1	)
Interest income		—			—			—			0.2			0.2
Interest expense		—			—			—			(7.3	)		(7.3	)
Income tax expense (b)		—			—			—			(0.1	)		(0.1	)
Net income (loss)		11.8			22.8			1.0			(15.8	)		19.8
Net loss attributable to noncontrolling interests		1.3			—			—			—			1.3
Net income (loss) attributable to partners	$	13.1		$	22.8		$	1.0		$	(15.8	)	$	21.1
Non-cash derivative mark-to-market (c)	$	0.1		$	0.2		$	—		$	(0.1	)	$	0.2
Capital expenditures	$	55.8		$	0.1		$	—		$	—		$	55.9
Acquisition expenditures	$	0.3		$	—		$	—		$	—		$	0.3
Investments in unconsolidated affiliates	$	0.2		$	—		$	—		$	—		$	0.2

	March 31, 2010		December 31, 2009
	(Millions)
Segment long-term assets:
Natural Gas Services	$	1,178.8	$	1,185.2
Wholesale Propane Logistics		52.9		53.2
NGL Logistics (d)		54.0		32.3
Other (e)		4.6		13.1
Total long-term assets		1,290.3		1,283.8
Current assets		173.9		197.7
Total assets	$	1,464.2	$	1,481.5

(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.

27

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

(b) Income tax expense relates primarily to the Texas margin tax and the Michigan business tax.

(c) Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.

(d) Long-term assets for our NGL Logistics segment increased in 2010 as a result of the Wattenberg pipeline acquisition for $22.0 million.

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

13. Supplemental Cash Flow Information

	Three Months Ended March 31,
	2010		2009
	(Millions)
Cash paid for interest, net of amounts capitalized	$	1.6	$	3.7
Cash paid for income taxes, net of income tax refunds	$	—	$	0.4
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	3.9	$	27.7
Other non-cash additions of property plant and equipment	$	0.2	$	0.9
Contingent consideration for the purchase of additional interest in a subsidiary	$	1.0	$	—

14. Subsequent Events

On April 27, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on May 14, 2010 to unitholders of record on May 7, 2010.

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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 2009 Form 10-K.

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. Our operations are organized into three business segments; Natural Gas Services, Wholesale Propane Logistics and NGL Logistics.

The financial information contained herein includes, for each period presented, our accounts, and the assets, liabilities and operations of our additional 25.1% limited liability company interest in East Texas acquired from DCP Midstream, LLC in April 2009, in transactions among entities under common control, which we refer to collectively as our “predecessor”. Transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, we owned a 25% limited liability company interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability interest in East Texas, and account for East Texas as a consolidated subsidiary.Accordingly, our financial information includes the historical results of our predecessor for all periods presented.

During the first quarter we have continued to experience improvements in the business environment compared to our experience in 2009. Crude oil and NGL prices have generally remained at favorable levels, although natural gas prices continue to remain lower than recent historical prices. With the exception of certain emerging gas shale regions where drilling activity remains high, the lower natural gas prices are resulting in reduced drilling activity in areas where the gas has a relatively lower liquid content. Gas production in regions with low liquid content receive less price uplift from the relatively higher crude and NGL prices. On a national basis, drilling levels have been gradually increasing over the past several months, although activity levels vary by geographic location.

During January and February, we experienced near record cold weather, causing operating challenges at our East Texas and North Louisiana plants, creating periods of low NGL recoveries and volume curtailments due to plant shutdowns and producer wellhead freeze offs. Financial results for the first quarter were in line with our 2010 forecast.

Improvements in the business environment along with opportunities in the market have enabled us to continue to execute on our growth objective. In January 2010, we completed a $22.0 million acquisition of our Wattenberg fee-based NGL pipeline and announced a related $18.0 million expansion capital project. We are optimistic about emerging growth opportunities and the continued execution of our growth strategy.

In 2010 we will integrate both the Michigan gathering and treating system we acquired in November 2009 as well as the Wattenberg NGL pipeline acquisition. We are well underway in executing on our integration plans and have launched the Wattenberg expansion project, which we expect to complete in early 2011.

General Trends and Outlook

In 2010, our strategic objectives will again focus on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our significant fee-based business representing over 50% of our estimated margins, and our highly hedged commodity position, the objective of which is to protect downside risk in our distributable cash flows.

We expect to incur maintenance capital of approximately $10 million to $15 million in 2010 to maintain our existing assets. We also expect to incur expansion capital in 2010 of approximately $30 million to $35 million, including approximately $18 million associated with the recently acquired Wattenberg pipeline. This capital does not include any additional investment opportunities that may be identified throughout the course of the year and approved by our management and our Board of Directors.

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In 2010 we expect to continue to pursue a multi-faceted growth strategy, including executing on organic opportunities around our footprint, third party acquisitions, and periodic dropdowns from our sponsors in order to grow our distributable cash flows. We also plan to fully integrate our recent acquisitions and execute on the Wattenberg pipeline expansion project, which positions this asset to provide cash flow contributions in early 2011.

We anticipate our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas Gathering and Processing Margins— Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could decline further should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, natural gas prices should return to a level that would support continued natural gas production in the United States. During 2010, petrochemical demand remains strong for NGLs as NGLs are a lower cost feedstock when compared to crude oil derived feedstocks.

Wholesale Propane Supply and Demand — Due to our multiple propane supply sources, propane supply contractual 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 peak demand periods of tight supply, usually in the winter months when their retail customers consume the most propane for home heating. We expect propane demand to continue to be negatively impacted during 2010 from the current recessionary environment.

For an in-depth discussion of factors that may significantly affect our results, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That May Significantly Affect Our Results” in our 2009 Form 10-K.

Recent Events

Gregory J. Goff informed DCP Midstream GP, LLC, or the general partner, of his resignation from the Board of Directors and the Compensation Committee of the Board of Directors of the general partner effective April 30, 2010. The general partner serves as the ultimate general partner of DCP Midstream Partners, LP. There were no disagreements between Mr. Goff and DCP Midstream Partners, LP or the general partner regarding operations, policies or practices.

On April 27, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on May 14, 2010 to unitholders of record on May 7, 2010.

In January 2010, we acquired the Wattenberg pipeline from Buckeye Partners, L.P., for $22.0 million in cash, funded with borrowings under our revolving credit facility. The 350-mile pipeline originates in the Denver-Julesburg, or DJ, Basin in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. We expect to spend approximately $18.0 million during 2010 in expansion capital to connect and integrate the acquired pipeline with DCP Midstream, LLC’s facilities, with cash flow contributions commencing in early 2011. In conjunction with our acquisition of the Wattenberg pipeline, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement is effective through November 2010, renewing on an evergreen basis thereafter. We have also agreed to the terms of an additional 10 year transportation agreement with DCP Midstream, LLC. The acquired pipeline will generate 100 percent fee-based revenues, with the results of the assets being included in our NGL logistics segment prospectively, from the date of acquisition.

In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso E&P Company, L.P., or El Paso to resolve all claims brought by El Paso in their lawsuits, filed in Texas and Louisiana, which stemmed from an ongoing commercial dispute involving our Minden processing plant. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement. The original judgment in Texas has now been vacated and all appeals have been dismissed in both Texas and Louisiana.

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Reconciliation of Non-GAAP Measures

Gross Margin, Segment Gross Margin and Adjusted Segment 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. We define adjusted segment gross margin as segment gross margin plus non-cash derivative losses, less non-cash derivative gains for that segment. Gross margin, segment gross margin and adjusted segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin, segment gross margin and adjusted segment gross margin should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

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

	Three Months Ended March  31,
	2010			2009
	(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of net income (loss) attributable to partners to gross margin:
Net income attributable to partners	$	25.8		$	21.1
Interest expense		7.2			7.3
Income tax expense		0.3			0.1
Operating and maintenance expense		19.0			16.2
Depreciation and amortization expense		17.8			14.6
General and administrative expense		8.6			8.6
Interest income		—			(0.2	)
(Earnings) losses from unconsolidated affiliates		(7.9	)		1.1
Net income (loss) attributable to noncontrolling interests		0.1			(1.3	)
Gross margin	$	70.9		$	67.5
Non-cash commodity derivative mark-to-market (a)	$	7.8		$	0.3

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	Three Months Ended March  31,
	2010			2009
	(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of segment net income (loss) attributable to partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners	$	27.9		$	13.1
Operating and maintenance expense		16.2			13.2
Depreciation and amortization expense		17.0			13.9
(Earnings) losses from unconsolidated affiliates		(7.4	)		1.5
Net income (loss) attributable to noncontrolling interests		0.1			(1.3	)
Segment gross margin	$	53.8		$	40.4
Non-cash commodity derivative mark-to-market (a)	$	8.4		$	0.1
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	10.8		$	22.8
Operating and maintenance expense		2.6			2.7
Depreciation and amortization expense		0.3			0.3
Segment gross margin	$	13.7		$	25.8
Non-cash commodity derivative mark-to-market (a)	$	(0.6	)	$	0.2
NGL Logistics segment:
Segment net income attributable to partners	$	3.2		$	1.0
Operating and maintenance expense		0.2			0.3
Depreciation and amortization expense		0.5			0.4
Earnings from unconsolidated affiliates		(0.5	)		(0.4	)
Segment gross margin	$	3.4		$	1.3

(a) Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.

Adjusted EBITDA and Distributable Cash Flow— We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Adjusted EBITDA is used as a supplemental liquidity and performance 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;

• 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.

Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, 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.

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We define Distributable Cash Flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation and income tax, 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 and performance 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.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in Item 7 in our 2009 Form 10-K. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three months ended March 31, 2010 are the same as those described in our 2009 Form 10-K.

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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, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion:

	Three Months Ended March 31,						Variance Three Months 2010 vs. 2009
	2010 (a)			2009 (a)(b)			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services (c)	$	218.1		$	149.8		$	68.3		46	%
Wholesale Propane Logistics		180.8			132.8			48.0		36	%
NGL Logistics		4.8			1.8			3.0		167	%
Total operating revenues		403.7			284.4			119.3		42	%
Gross margin (d):
Natural Gas Services		53.8			40.4			13.4		33	%
Wholesale Propane Logistics		13.7			25.8			(12.1	)	(47	)%
NGL Logistics		3.4			1.3			2.1		162	%
Total gross margin		70.9			67.5			3.4		5	%
Operating and maintenance expense		(19.0	)		(16.2	)		2.8		17	%
Depreciation and amortization expense		(17.8	)		(14.6	)		3.2		22	%
General and administrative expense		(8.6	)		(8.6	)		—		—	%
Earnings (losses) from unconsolidated affiliates (e)		7.9			(1.1	)		9.0		*
Interest income		—			0.2			(0.2	)	(100	)%
Interest expense		(7.2	)		(7.3	)		(0.1	)	(1	)%
Income tax expense		(0.3	)		(0.1	)		0.2		200	%
Net (income) loss attributable to noncontrolling interests		(0.1	)		1.3			(1.4	)	*
Net income attributable to partners	$	25.8		$	21.1		$	4.7		22	%
Other data:
Non-cash commodity derivative mark-to-market	$	7.8		$	0.3		$	7.5		2,500	%
Natural gas throughput (MMcf/d) (e)		1,164			995			169		17	%
NGL gross production (Bbls/d) (e)		32,874			21,832			11,042		51	%
Propane sales volume (Bbls/d)		33,356			37,092			(3,736	)	(10	)%
NGL pipelines throughput (Bbls/d) (e)		39,911			23,969			15,942		67	%

* Percentage change is not meaningful.

(a) Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company, since November 24, 2009 the date of acquisition, in our Natural Gas Services segment.

Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P., since January 28, 2010 the date of acquisition in our NGL Logistics segment.

(b) In April 2009, we completed the acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC, which results in us owning a 50.1% limited liability company interest in East Texas. Prior to this transaction, we accounted for our interest in East Texas under the equity method of accounting. As a result of our owning in excess of 50%, and because the transaction was between entities under common control, we are required to present results of operations, including all historical periods, on a consolidated basis. Therefore, these results as presented are different from those originally reported in the first quarter of 2009, which excluded the impact of this transaction. Our gross margin for our Natural Gas Services segment changed from $30.7 million as previously reported in 2009, to $40.4 as currently reported, for the three months ended March 31, 2009.

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Additionally, while we utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

(c) Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010.

(d) 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 “Reconciliation of Non-GAAP Measures” above.

(e) Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson Pipeline Company, or Jackson, East Texas, Black Lake and Discovery and our proportionate earnings of Black Lake and Discovery. Earnings for Discovery and Black Lake include the accretion of the net difference between the carrying amount of the investments and the underlying equity of the investments.

Three Months Ended March 31, 2010 vs. Three Months Ended March 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $63.9 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, and an increase in NGL production, partially offset by the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the impact of a fire at East Texas and our Wyoming pipeline integrity and system enhancement project;

• $48.2 million increase primarily attributable to higher propane prices, which impact both sales and purchases, partially offset by decreased sales volumes for our Wholesale Propane Logistics segment; and

• $7.0 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to our Michigan and Wattenberg acquisitions, as well as increases across certain other assets.

These increases were partially offset by:

• $1.0 million decrease related to commodity derivative activity. This decrease in gains includes an increase in realized cash settlement losses of $8.4 million due to generally higher average prices of commodities in 2010, partially offset by an increase in unrealized gains of $7.4 million due to movements in forward prices of commodities.

Gross Margin — Gross margin increased in 2010 compared to 2009, primarily as a result of the following:

• $13.4 million increase for our Natural Gas Services segment, primarily as a result of higher commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged, increased fee-based throughput volumes resulting from the Michigan acquisition and changes in contract mix, partially offset by decreased marketing activity and natural gas volumes across certain of our assets, as well as the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana. 2009 results include the impact of a fire at East Texas and operational downtime; and

• $2.1 million increase for our NGL Logistics segment as a result of higher volumes and per unit margins.

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These increases were partially offset by:

• $12.1 million decrease for our Wholesale Propane Logistics segment. 2009 results reflect increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our Michigan acquisition and capital projects completed in 2009.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our Michigan acquisition and our capital projects completed in 2009.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2010 compared to 2009, primarily as a result of increased earnings from Discovery. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Net (income) loss attributable to noncontrolling interests — Net (income) loss attributable to noncontrolling interests includes a net loss at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2010 results include the impact of severe weather and operational challenges at East Texas initiated by weather. 2009 results include the impact of a fire at East Texas.

Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system, a 40% limited liability company interest in Discovery, our Colorado and Wyoming systems, our East Texas systems, and our Michigan systems.

	Three Months Ended March 31,						Variance Three Months 2010 vs. 2009
	2010 (a)			2009 (a)(b)			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	187.6		$	123.7		$	63.9		52	%
Transportation, processing and other		24.3			19.1			5.2		27	%
Gains from commodity derivative activity (c)		6.2			7.0			(0.8	)	(11	)%
Total operating revenues		218.1			149.8			68.3		46	%
Purchases of natural gas and NGLs		164.3			109.4			54.9		50	%
Segment gross margin (d)		53.8			40.4			13.4		33	%
Operating and maintenance expense		(16.2	)		(13.2	)		3.0		23	%
Depreciation and amortization expense		(17.0	)		(13.9	)		3.1		22	%
Earnings (losses) from unconsolidated affiliates (e)		7.4			(1.5	)		8.9		*
Segment net income		28.0			11.8			16.2		137	%
Segment net (income) loss attributable to noncontrolling interests		(0.1	)		1.3			(1.4	)	*
Segment net income attributable to partners	$	27.9		$	13.1		$	14.8		113	%
Other data:
Non-cash commodity derivative mark-to-market	$	8.4		$	0.1		$	8.3		8,300	%
Natural gas throughput (MMcf/d) (e)		1,164			995			169		17	%
NGL gross production (Bbls/d) (e)		32,874			21,832			11,042		51	%

* Percentage change is not meaningful.

(a) Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company, since November 24, 2009 the date of acquisition.

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(b) In April 2009, we completed the acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC, which results in us owning a 50.1% limited liability company interest in East Texas. Prior to this transaction, we accounted for our interest in East Texas under the equity method of accounting. As a result of our owning in excess of 50%, and because the transaction was between entities under common control, we are required to present results of operations, including all historical periods, on a consolidated basis. Therefore, these results as presented are different from those originally reported in the first quarter of 2009, which excluded the impact of this transaction. Our gross margin for our Natural Gas Services segment changed from $30.7 million as previously reported in 2009, to $40.4 as currently reported, for the three months ended March 31, 2009.

Additionally, while we utilize commodity derivative instruments to provide stability to distributable cash flows for our ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

(c) Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010.

(d) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

(e) Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson, East Texas and Discovery and our proportionate share of the earnings of Discovery for each period presented. Earnings for Discovery include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

Three Months Ended March 31, 2010 vs. Three Months Ended March 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $58.0 million increase attributable to increased commodity prices, which impact both sales and purchases, and includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged;

• $5.9 million increase due primarily to increased NGL production and a prospective change to a contract with an affiliate in the Piceance Basin, such that certain revenues changed from a net presentation in transportation, processing and other to a gross presentation in sales of natural gas, NGLs and condensate, partially offset by the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the impact of a fire in East Texas and our Wyoming pipeline integrity and system enhancement project; and

• $5.2 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, changes in contract mix, as well as increases across certain other assets.

These increases were partially offset by:

• $0.8 million decrease related to commodity derivative activity. This decrease in gains includes an increase in realized cash settlement losses of $9.0 million due to generally higher average prices of commodities in 2010, partially offset by an increase in unrealized gains of $8.2 million due to movements in forward prices of commodities.

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Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2010 compared to 2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a prospective change to a contract with an affiliate in the Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and other to a gross presentation in purchases of natural gas and NGLs.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, primarily as a result of the following:

• $14.7 million increase as a result of higher commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged; and

• $5.2 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, changes in contract mix, as well as increases across certain other assets.

These increases were partially offset by:

• $5.7 million decrease in volumes attributable to reduced marketing activity, the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana, and other natural gas volume reductions across certain of our assets, partially offset by increased throughput volumes from our organic growth project in the Piceance Basin. 2009 results include the impact of a fire in East Texas and our Wyoming pipeline integrity and system enhancement project; and

• $0.8 million decrease related to commodity derivative activities as discussed in the Operating Revenues section above.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our Michigan acquisition, our capital projects completed in 2009, repairs as a result of near record cold weather and efficiency projects.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Michigan acquisition and our capital projects completed in 2009.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, increased in 2010 compared to 2009. The increase in Discovery’s earnings are primarily as a result of increased volumes from the Tahiti project and higher rates, partially offset by increased depreciation and plant fuel costs. 2009 results include the impact of hurricanes. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Segment net (income) loss attributable to noncontrolling interests — Segment net (income) loss attributable to noncontrolling interests includes a net loss at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2010 results include the impact of severe weather and operational challenges at East Texas initiated by weather. 2009 results include the impact of a fire at East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2010 compared to 2009, as a result of increased fee-based throughput volumes from our Michigan acquisition, and increased volumes from the Tahiti project at Discovery, partially offset by decreased volumes across certain assets. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana. 2009 results include the impact of operational downtime following the hurricanes, a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

NGL Gross Production — NGL production increased in 2010 compared to 2009, due primarily to increased NGL production from the Tahiti project at Discovery and increased volumes from our Piceance Basin expansion project. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana initiated by weather. 2009 results include the impact of operational downtime following the hurricanes, a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

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Results of Operations— Wholesale Propane Logistics Segment

This segment includes our propane transportation facilities, which includes five owned and operated rail terminals, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals.

	Three Months Ended March 31,						Variance Three Months 2010 vs. 2009
	2010			2009			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of propane	$	181.0		$	132.8		$	48.2		36	%
Losses from commodity derivative activity		(0.2	)		—			(0.2	)	(100	)%
Total operating revenues		180.8			132.8			48.0		36	%
Purchases of propane		167.1			107.0			60.1		56	%
Segment gross margin (a)		13.7			25.8			(12.1	)	(47	)%
Operating and maintenance expense		(2.6	)		(2.7	)		(0.1	)	(4	)%
Depreciation and amortization expense		(0.3	)		(0.3	)		—		—	%
Segment net income attributable to partners	$	10.8		$	22.8		$	(12.0	)	(53	)%
Other data:
Non-cash commodity derivative mark-to-market	$	(0.6	)	$	0.2		$	(0.8	)	*
Propane sales volume (Bbls/d)		33,356			37,092			(3,736	)	(10	)%

* Percentage change is not meaningful.

(a) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “Reconciliation of Non-GAAP Measures” above.

Three Months Ended March 31, 2010 vs. Three Months Ended March 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $59.2 million increase attributable to higher propane prices, which impact both sales and purchases.

This increase was partially offset by:

• $11.0 million decrease attributable to decreased propane sales volumes; and

• $0.2 million decrease related to commodity derivative activity.

Purchases of Propane — Purchases of propane increased in 2010 compared to 2009, as a result of higher propane prices, which impact both sales and purchases, partially offset by decreased volumes.

Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009. 2009 results reflect increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Propane Sales Volume — Propane sales volumes decreased in 2010 compared to 2009. 2009 results reflect an increase in spot sales volumes.

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Results of Operations— NGL Logistics Segment

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

	Three Months Ended March 31,						Variance Three Months 2010 vs. 2009
	2010 (a)			2009			Increase (Decrease)			Percent
Operating revenues:
Sales of NGLs	$	1.8		$	0.6		$	1.2		200	%
Transportation, processing and other		3.0			1.2			1.8		150	%
Total operating revenues		4.8			1.8			3.0		167	%
Purchases of NGLs		1.4			0.5			0.9		180	%
Segment gross margin (b)		3.4			1.3			2.1		162	%
Operating and maintenance expense		(0.2	)		(0.3	)		(0.1	)	(33	)%
Depreciation and amortization expense		(0.5	)		(0.4	)		0.1		25	%
Earnings from unconsolidated affiliates (c)		0.5			0.4			0.1		25	%
Segment net income attributable to partners	$	3.2		$	1.0		$	2.2		220	%
Other data:
NGL pipelines throughput (Bbls/d) (c)		39,911			23,969			15,942		67	%

(a) Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P., since January 28, 2010, the date of acquisition.

(b) Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

(c) Includes our proportionate share of the throughput volumes and earnings of Black Lake for all periods presented. Earnings for Black Lake include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

Three Months Ended March 31, 2010 vs. Three Months Ended March 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of increased throughput volumes from a market opportunity at Seabreeze and the Wattenberg pipeline acquisition, as well as higher per unit margins. 2009 results include the impact of decreased throughput volumes resulting from ethane rejection and lower volumes at certain connected processing plants.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, as a result of higher volumes and per unit margins.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result of increased volumes from a market opportunity at Seabreeze and the Wattenberg pipeline acquisition. 2009 results include the impact of ethane rejection and lower volumes at certain connected processing plants.

Liquidity and Capital Resources

We expect our sources of liquidity to include:

• cash generated from operations;

• cash distributions from our unconsolidated affiliates;

• borrowings under our revolving credit facility;

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• issuance of additional partnership units;

• debt offerings;

• guarantees issued by DCP Midstream, LLC, which reduce the amount of collateral we may be required to post with certain counterparties to our commodity derivative instruments; and

• letters of credit.

We anticipate our more significant uses of resources to include:

• capital expenditures;

• quarterly distributions to our unitholders;

• contributions to our unconsolidated affiliates to finance our share of their capital expenditures;

• business and asset acquisitions; and

• collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and which is required to the extent we exceed certain guarantees issued by DCP Midstream, LLC and letters of credit we have posted.

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. In the event these sources are not sufficient, we would reduce our discretionary spending.

We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations.

During the first quarter of 2010 and the latter part of 2009, there has been a general improvement in the market for and the valuations of equity securities and a general improvement in the availability and costs of funds obtained in the public and private debt markets, as compared with the latter part of 2008 and early 2009. Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our business, although deterioration in our operating environment could limit our borrowing capacity, raise our financing costs, as well as impact our compliance with our financial covenant requirements under our Credit Agreement. Our sources of funding could include additional borrowings under our Credit Agreement, the placement of public and private debt, and the issuance of our common units.

Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2015 with fixed price natural gas and crude oil swaps. For additional information regarding our derivative activities, please read “Item7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2009 Form 10-K and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report on Form 10-Q.

We have a 5-year credit agreement, or the Credit Agreement, consisting of a $824.6 million revolving credit facility at March 31, 2010. Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts borrowed under the Credit Agreement will not mature prior to the June 21, 2012 maturity date. As of May 6, 2010, we had approximately $205.3 million of borrowing capacity under the Credit Agreement.

        The counterparties to each of our commodity 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 6, 2010, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $108.0 million in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. We pay DCP Midstream LLC a fee of 0.50% per annum on $65.0 million of these guarantees. As of May 6, 2010 we had a letter of credit of $10.0 million, on which we pay a fee of 0.75% per annum. These parental guarantees and letter of credit reduce 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. As of May 6, 2010, we had no cash collateral posted with counterparties. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. Predetermined collateral thresholds for commodity derivative instruments 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.

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Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced by our quarterly distributions, which are required under the terms of our partnership agreement based on Available Cash, as defined in the partnership agreement. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and 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.

As of March 31, 2010, we had $2.6 million in cash and cash equivalents. Of this balance, as of March 31, 2010, $2.2 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the cash held by these subsidiaries, this cash balance was available for general corporate purposes.

We had a working capital deficit of $7.2 million and working capital of $6.6 million as of March 31, 2010 and December 31, 2009, respectively. Excluding net derivative working capital liabilities of $34.6 million and $34.2 million, working capital would be $27.4 million and $40.8 million as of March 31, 2010 and December 31, 2009, respectively. The change in working capital is primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.

Cash Flow —Operating, investing and financing activities was as follows:

	Three Months Ended March  31,
	2010			2009
	(Millions)
Net cash provided by operating activities	$	51.0		$	30.5
Net cash used in investing activities	$	(24.6	)	$	(56.6	)
Net cash used in financing activities	$	(25.9	)	$	(23.8	)

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 paid net cash for settlement of our commodity derivative instruments of $2.2 million for the three months ended March 31, 2010 and received cash for settlement of our commodity derivative instruments of $6.2 million for the three months ended March 31, 2009.

We received cash distributions from unconsolidated affiliates of $9.8 million and $0.5 million during the three months ended March 31, 2010 and 2009, respectively. Distributions exceeded earnings by $1.9 million and $1.6 million for the three months ended March 31, 2010 and 2009, respectively.

Net Cash Used in Investing Activities — Net cash used in investing activities during the three months ended March 31, 2010 was comprised of: (1) acquisition expenditure of $22.0 million related to our acquisition of the Wattenberg NGL pipeline; (2) capital expenditures of $12.2 million (our portion of which was $6.8 million and the noncontrolling interest holders’ portion was $5.4 million); (3) investments in Discovery of $0.7 million; partially offset by (4) net proceeds from sale of available-for-sale securities of $10.1 million; and (5) proceeds from sale of assets of $0.2 million.

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Net cash used in investing activities during the three months ended March 31, 2009 was comprised of: (1) capital expenditures of $55.9 million (our portion of which was $26.0 million and the noncontrolling interest holders’ portion was $29.9 million), which primarily consisted of expenditures for expansion of our Collbran system and East Texas systems and completion of the pipeline integrity system upgrades to our Wyoming system; (2) a payment of $0.3 million related to our acquisition of Michigan Pipeline & Processing, LLC; (3) investments in Discovery of $0.2 million; and (4) net purchases of available-for-sale securities of $0.2 million.

Net Cash Used in Financing Activities —Net cash used in financing activities during the three months ended March 31, 2010 was comprised of (1) distributions to our unitholders and general partner of $24.6 million; (2) distributions to noncontrolling interests of $3.7 million; and (3) purchase of additional interest in a subsidiary of $3.5 million; partially offset by (4) contributions from noncontrolling interests of $3.9 million; and (5) net borrowings of $2.0 million.

Net cash used in financing activities during the three months ended March 31, 2009 was comprised of (1) distributions to our unitholders of $20.1 million; and (2) payments of debt of $11.5 million; partially offset by (3) net contributions from noncontrolling interests of $4.8 million; and (4) net changes in advances to predecessor from DCP Midstream, LLC of $3.0 million.

During the three months ended March 31, 2010, total outstanding indebtedness under our $824.6 million Credit Agreement, which includes borrowings under our revolving credit facility, our term loan facility and letters of credit issued under the Credit Agreement, was not less than $612.2 million and did not exceed $647.2 million. The weighted average indebtedness outstanding for the three months ended March 31, 2010 was $622.5 million.

We had liquidity, which is available commitments under the Credit Agreement of $209.3 million as of March 31, 2010.

During the three months ended March 31, 2010, we had the following net movements on our revolving credit facility:

• $22.0 million borrowing to fund the acquisition of the Wattenberg pipeline; and

• $10.0 million borrowing to fund repayment of our term loan facility; partially offset by

• $20.0 million net repayments.

During the three months ended March 31, 2010, we had a repayment of $10.0 million on our term loan facility and released $10.0 million of restricted investments which were required as collateral for the facility.

During the three months ended March 31, 2009, we had no incremental borrowings under our Credit Agreement and we repaid $11.5 million on our revolving credit facility.

We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 10 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.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $10 million and $15 million, and expansion capital expenditures of between $30 million and $35 million for the year ending December 31, 2010, which includes $18 million of expansion capital related to our January 2010 Wattenberg pipeline acquisition. The board of directors may approve additional growth capital during the year, at their discretion.

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The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities.

	Three Months Ended March 31, 2010						Three Months Ended March 31, 2009
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)						(Millions)
Our portion	$	3.0	$	3.8	$	6.8	$	7.4	$	18.6	$	26.0
Noncontrolling interest portion		3.6		1.8		5.4		9.3		20.6		29.9
Total	$	6.6	$	5.6	$	12.2	$	16.7	$	39.2	$	55.9

In addition, we invested cash in unconsolidated affiliates of $0.7 million and $0.2 million during the three months ended March 31, 2010 and 2009, respectively, to fund our share of capital expansion projects.

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, which could include debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our credit facility and the issuance of additional partnership units or debt. If these sources are not sufficient, we will reduce our discretionary spending.

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 and general partner of $24.6 million during the three months ended March 31, 2010, as compared to $20.1 million for the same period in 2009. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.

Credit Rating

The table below presents our current credit rating.

Rating Agency	Date of Rating Initiation	Outlook	Credit Rating
Standard & Poor’s	December 7, 2009	Stable	BBB-

Standard & Poor’s, or S&P, considers “BBB-” the lowest investment grade rating, and a rating below investment grade indicates that the security has significant speculative characteristics. S&P may modify its ratings with a “+” or a “–” sign to show the obligor’s relative standing within a major rating category.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating organization.

Description of the Credit Agreement — We have a 5-year credit agreement, or the Credit Agreement, consisting of a $824.6 million revolving credit facility at March 31, 2010. The Credit Agreement matures on June 21, 2012. As of March 31, 2010, the outstanding balance on the revolving credit facility was $615.0 million.

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 or construction of assets in the midstream energy business. The unused portion of the revolving credit facility may be used for letters of credit. At March 31, 2010 and December 31, 2009, we had outstanding letters of credit issued under the Credit Agreement of $0.3 million.

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As of March 31, 2010, the weighted-average interest rate on our revolving credit facility was 0.70% per annum.

Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of March 31, 2010, is as follows:

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(Millions)
Long-term debt (a)	$	672.4	$	26.2	$	646.2	$	—	$	—
Operating lease obligations (b)		47.1		14.0		22.2		9.8		1.1
Purchase obligations (c)		850.8		245.9		330.8		204.3		69.8
Other long-term liabilities (d)		9.6		—		0.5		0.2		8.9
Total	$	1,579.9	$	286.1	$	999.7	$	214.3	$	79.8

(a) Includes interest payments on long-term debt that has been hedged. Interest payments on long-term debt that has not been hedged are not included as these payments are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments.

(b) Our operating lease obligations are off-balance sheet obligations, and primarily consist of our leased marine propane terminal and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics business. Operating lease obligations also include firm transportation arrangements and natural gas storage for our Pelico system. The firm transportation arrangements supply off-system natural gas to Pelico and the natural gas storage arrangement enables us to maximize the value between the current price of natural gas and the futures market price of natural gas.

(c) Our purchase obligations are off balance sheet obligations and include $2.2 million of purchase orders for capital expenditures and $592.8 million of various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business. For contracts where the price paid is based on an index, the amount is based on the forward market prices at March 31, 2010. 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.

(d) Other long-term liabilities include $8.9 million of asset retirement obligations and $0.7 million of environmental reserves recognized in the March 31, 2010 condensed consolidated balance sheet.

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Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,”or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended the Accounting Standards Codification, or ASC, Topic 820-10 “Fair Value Measurement and Disclosures — Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,”or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our condensed financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,”or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2009 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.

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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 $575.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. 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, 2010, the effective weighted-average interest rate on our $615.0 million of outstanding revolver debt was 4.33%, taking into account the $575.0 million of indebtedness with designated interest rate swaps.

Based on the annualized unhedged borrowings under our credit facility of $40.0 million as of March 31, 2010, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $0.2 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, sales and storage activities. For gathering services, we receive fees or commodities from producers to bring the 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 fixed price natural gas, crude oil and NGL contracts to mitigate a portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of these instruments prior to their maturity.

We enter into derivative financial instruments to mitigate a portion of the cash flow risk of decreased natural gas, NGL and condensate prices associated with our percent-of-proceeds arrangements and gathering operations. We also may enter into natural gas derivatives to lock in margin around our transportation or leased storage assets. Historically, there has been a strong relationship between NGL prices and crude oil prices, with some exceptions, notably in late 2008 and early 2009, and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is outside of historical ranges, we experience additional exposure as a result of the relationship. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2015.

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.

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.

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The following table sets forth additional information about our fixed price natural gas and crude oil swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations as of May 6, 2010:

Period	Commodity	Notional Volume	Reference Price	Swap Price Range
April 2010 — December 2010	Natural Gas	1,634 MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$3.94/MMBtu
January 2011 — December 2012	Natural Gas	1000/ MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$5.89/MMBtu
April 2010 — December 2010	Natural Gas	1,900 MMBtu/d	Texas Gas Transmission Price (b)	$6.41 - $9.20/MMBtu
January 2011 — December 2012	Natural Gas	1,100 MMBtu/d	Texas Gas Transmission Price (b)	$6.41 - $6.80/MMBtu
April 2010 — December 2013	Natural Gas	1,000 MMBtu/d	NYMEX Final Settlement Price (c)	$8.22/MMBtu
April 2010 — December 2013	Natural Gas Basis	1,000 MMBtu/d	IFERC Monthly Index Price for Panhandle Eastern Pipe Line (d)	NYMEX less $0.68/MMBtu
April 2010 — December 2010	Crude Oil	2,415 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$63.05 - $87.25/Bbl
April 2010 — December 2011	Crude Oil	250 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$56.75 - $59.30/Bbl
January 2011 — December 2011	Crude Oil	2,350 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$66.72 - $83.80/Bbl
January 2012 — December 2012	Crude Oil	2,125 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$66.72 - $90.00/Bbl
January 2013 — December 2013	Crude Oil	2,050 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$67.60 - $83.00/Bbl
January 2014 — December 2014	Crude Oil	1,500 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$74.90 - $96.08/Bbl
January 2015 — December 2015	Crude Oil	500 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$92.00/Bbl

(a) The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline.

(b) The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area.

(c) NYMEX final settlement price for natural gas futures contracts (NG).

(d) The Inside FERC monthly published index price for Panhandle Eastern Pipe Line (Texas, Oklahoma – mainline) less the NYMEX final settlement price for natural gas futures contracts.

(e) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).

Our annual sensitivities for 2010 as shown in the table below, exclude the impact from non-cash mark-to-market on our commodity derivatives. We utilize crude oil derivatives to mitigate a portion of our commodity price exposure for NGLs, and show our sensitivity to changes in the relationship between the pricing of NGLs and crude oil. For fixed price natural gas and crude oil, the sensitivities are associated with our unhedged volumes. For our NGL to crude oil price relationship, the sensitivity is associated with both hedged and unhedged equity volumes.

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Commodity Sensitivities Excluding Non-Cash Mark-To-Market

	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	0.2
Crude oil prices (a)	$	5.00	Barrel	$	1.3
NGL to crude oil price relationship (b)		5 percentage point change	Barrel	$	5.6

(a) Assuming 60% NGL to crude oil price relationship.

(b) Assuming 60% NGL to crude oil price relationship and $70.00/Bbl crude oil price. Generally, this sensitivity changes by $1.6 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from $70.00/Bbl, we become slightly more sensitive to the change in the relationship of NGL prices to crude oil prices. As crude oil prices decrease from $70.00/Bbl, we become less sensitive to the change in the relationship of NGL prices to crude oil prices.

In addition to the linear relationships in our commodity sensitivities above, additional factors cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a certain percentage of liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as NGL prices decline.

The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the natural gas would yield favorable processing margins. Less than 10% of our gas throughput is associated with these arrangements.

We estimate the following non-cash sensitivities in 2010 related to the mark-to-market on our commodity derivatives associated with our commodity cash flow protection activities:

Non-Cash Mark-To-Market Commodity Sensitivities

	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market  Impact (Decrease in Net Income Attributable to Partners)
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	4.0
Crude oil prices	$	5.00	Barrel	$	19.9
NGL prices	$	0.10	Gallon	$	0.3

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 relationship 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 in turn has been generally related to the price of crude oil, with some exceptions, notably in late 2008 and early 2009, when NGL pricing was at a greater discount to crude oil pricing. Although the prevailing price of residue 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. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2015. Given the historical relationship between NGL prices and crude oil prices and the lack of liquidity in the NGL financial market, we have generally used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is outside of historical ranges, we experience additional exposure as a result of the relationship.

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Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. We believe that future natural gas prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and imports of liquid natural gas, or LNG, from foreign locations. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also further reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall below demand levels.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, including the Chief Executive Officer and the Chief Financial Officer, of DCP Midstream GP, LLC, has 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 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 quarter ended March 31, 2010 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 17, “Commitments and Contingent Liabilities,” included in Item 8 of our 2009 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 2009 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 2009 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 condensed consolidated results of operations, financial condition and cash flows.

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Item 6. Exhibits

Exhibits

Exhibit Number	Description
3.1 *	First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP (attached as Exhibit 3.4 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.2 *	First Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC (attached as Exhibit 3.6 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.3 *	Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.4 *	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.5 *	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated as of April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.6 *	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

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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 10, 2010.

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/ Angela A. Minas
Name:	Angela A. Minas
Title:	Vice President and Chief Financial Officer
	(Principal Financial Officer)

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EXHIBIT INDEX

Exhibit Number	Description
3.1 *	First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP (attached as Exhibit 3.4 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.2 *	First Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC (attached as Exhibit 3.6 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.3 *	Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.4 *	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.5 *	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated as of April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.6 *	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

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