Edgar Filing: DCP Midstream Partners, LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

¨	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.

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 August 5, 2010, there were outstanding 34,608,183 common units representing limited partner interests.

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2010

TABLE OF CONTENTS


Item		Page
	PART I. FINANCIAL INFORMATION

1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	2
	Condensed Consolidated Statements of Comprehensive Income (loss) for the Three and Six Months Ended June 30, 2010 and 2009	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	4
	Condensed Consolidated Statements of Changes in Equity for the Six Months Ended June 30, 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	42
3.	Quantitative and Qualitative Disclosures about Market Risk	64
4.	Controls and Procedures	68

	PART II. OTHER INFORMATION

1.	Legal Proceedings	68
1A.	Risk Factors	68
6.	Exhibits	70

	Signatures	71
	Exhibit Index	72

	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002
	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002
	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002
	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

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

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, or the Credit Agreement, and our ability to maintain our credit ratings;

•

our ability to purchase propane from our principal suppliers and make associated profitable sales transactions 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;

•

additions and 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, including changes resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

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)


	June 30, 2010			December 31, 2009
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	4.8		$	2.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.7 million and $0.5 million, respectively		43.4			78.7
Affiliates		61.0			73.8
Inventories		19.6			34.2
Unrealized gains on derivative instruments		2.8			7.3
Assets held for sale		1.6			—
Other		1.5			1.6

Total current assets		134.7			197.7
Restricted investments		—			10.0
Property, plant and equipment, net		1,008.5			1,000.1
Goodwill		92.1			92.1
Intangible assets, net		58.9			60.5
Investments in unconsolidated affiliates		109.8			114.6
Unrealized gains on derivative instruments		5.2			2.0
Other long-term assets		4.0			4.5

Total assets	$	1,413.2		$	1,481.5

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	67.0		$	85.5
Affiliates		19.3			43.1
Unrealized losses on derivative instruments		30.3			41.5
Accrued interest payable		0.8			0.7
Other		23.4			20.3

Total current liabilities		140.8			191.1
Long-term debt		615.0			613.0
Unrealized losses on derivative instruments		39.4			58.0
Other long-term liabilities		14.2			14.0

Total liabilities		809.4			876.1


Commitments and contingent liabilities

Equity:
Common unitholders (34,608,183 units issued and outstanding)		419.1			415.5
General partner unitholders		(5.8	)		(5.9	)
Accumulated other comprehensive loss		(33.7	)		(31.9	)

Total partners’ equity		379.6			377.7
Noncontrolling interests		224.2			227.7

Total equity		603.8			605.4

Total liabilities and equity	$	1,413.2		$	1,481.5

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	93.2		$	71.8		$	328.6		$	229.0
Sales of natural gas, propane, NGLs and condensate to affiliates		134.8			101.9			269.8			201.8
Transportation, processing and other		22.1			20.7			43.7			37.4
Transportation, processing and other to affiliates		4.9			3.5			10.6			7.1
Gains (losses) from commodity derivative activity, net		22.8			(44.0	)		28.8			(36.3	)
Losses from commodity derivative activity, net — affiliates		(0.3	)		(1.9	)		(0.3	)		(2.6	)

Total operating revenues		277.5			152.0			681.2			436.4

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		178.1			110.6			369.6			248.4
Purchases of natural gas, propane and NGLs from affiliates		27.6			37.7			168.9			116.8
Operating and maintenance expense		20.6			17.1			39.6			33.3
Depreciation and amortization expense		18.7			16.3			36.5			30.9
General and administrative expense		3.4			2.0			7.1			5.2
General and administrative expense — affiliates		4.8			5.1			9.7			10.5
Other income		(0.5	)		—			(0.5	)		—
Other income — affiliates		(3.0	)		—			(3.0	)		—

Total operating costs and expenses		249.7			188.8			627.9			445.1

Operating income (loss)		27.8			(36.8	)		53.3			(8.7	)
Interest income		—			0.1			—			0.3
Interest expense		(7.3	)		(7.0	)		(14.5	)		(14.3	)
Earnings from unconsolidated affiliates		6.6			3.7			14.5			2.6

Income (loss) before income taxes		27.1			(40.0	)		53.3			(20.1	)
Income tax expense		(0.1	)		—			(0.4	)		(0.1	)

Net income (loss)		27.0			(40.0	)		52.9			(20.2	)
Net income attributable to noncontrolling interests		(1.0	)		(2.1	)		(1.1	)		(0.8	)

Net income (loss) attributable to partners		26.0			(42.1	)		51.8			(21.0	)
Net loss attributable to predecessor operations		—			—			—			1.0
General partner unitholders’ interest in net income		(4.2	)		(2.7	)		(8.0	)		(5.9	)

Net income (loss) allocable to limited partners	$	21.8		$	(44.8	)	$	43.8		$	(25.9	)


Net income (loss) per limited partner unit — basic and diluted	$	0.63		$	(1.41	)	$	1.27		$	(0.86	)


Weighted-average limited partner units outstanding — basic and diluted		34.6			31.7			34.6			30.0

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Millions)
Net income (loss)	$	27.0		$	(40.0	)	$	52.9		$	(20.2	)

Other comprehensive loss:
Reclassification of cash flow hedge losses into earnings		5.6			4.7			11.6			9.2
Net unrealized (losses) gains on cash flow hedges		(5.8	)		4.8			(13.4	)		0.3

Total other comprehensive (loss) income		(0.2	)		9.5			(1.8	)		9.5

Total comprehensive income (loss)		26.8			(30.5	)		51.1			(10.7	)
Total comprehensive income attributable to noncontrolling interests		(1.0	)		(2.1	)		(1.1	)		(0.8	)

Total comprehensive income (loss) attributable to partners	$	25.8		$	(32.6	)	$	50.0		$	(11.5	)

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2010			2009
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	52.9		$	(20.2	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		36.5			30.9
Earnings from unconsolidated affiliates		(14.5	)		(2.6	)
Distributions from unconsolidated affiliates		20.0			3.0
Other, net		1.1			(0.2	)

Change in operating assets and liabilities, which provided (used) cash net of effects of acquisitions:
Accounts receivable		47.8			22.8
Inventories		14.6			4.0
Net unrealized (gains) losses on derivative instruments		(30.3	)		54.0
Accounts payable		(42.5	)		(38.0	)
Accrued interest		0.1			(0.5	)
Other current assets and liabilities		2.8			(2.3	)
Other long-term assets and liabilities		0.2			0.4

Net cash provided by operating activities		88.7			51.3


INVESTING ACTIVITIES:
Capital expenditures		(25.4	)		(118.4	)
Acquisitions, net of cash acquired		(22.0	)		(0.1	)
Investments in unconsolidated affiliates		(0.7	)		(5.8	)
Proceeds from sale of assets		1.7			0.3
Purchases of available-for-sale securities		—			(1.1	)
Proceeds from sales of available-for-sale securities		10.1			26.1

Net cash used in investing activities		(36.3	)		(99.0	)


FINANCING ACTIVITIES:
Proceeds from debt		210.6			68.3
Payments of debt		(208.6	)		(86.8	)
Net change in advances to predecessor from DCP Midstream, LLC		—			3.0
Distributions to unitholders and general partner		(49.1	)		(40.2	)
Distributions to noncontrolling interests		(8.2	)		(4.9	)
Contributions from noncontrolling interests		9.1			50.3
Contributions from DCP Midstream, LLC		—			0.7
Purchase of additional interest in a subsidiary		(3.5	)		—

Net cash used in financing activities		(49.7	)		(9.6	)


Net change in cash and cash equivalents		2.7			(57.3	)
Cash and cash equivalents, beginning of period		2.1			61.9

Cash and cash equivalents, end of period	$	4.8		$	4.6

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)


	Partners’ Equity
	Predecessor Equity			Common Unitholders			Class D 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		—			(41.5	)		—			—			(7.6	)		—			(8.2	)		(57.3	)
Contributions		—			—			—			—			—			—			9.1			9.1

Comprehensive income (loss):
Net income		—			44.1			—			—			7.7			—			1.1			52.9
Reclassification of cash flow hedges into earnings		—			—			—			—			—			11.6			—			11.6
Net unrealized losses on cash flow hedges		—			—			—			—			—			(13.4	)		—			(13.4	)

Total comprehensive income (loss)		—			44.1			—			—			7.7			(1.8	)		1.1			51.1

Balance, June 30, 2010	$	—		$	419.1		$	—		$	—		$	(5.8	)	$	(33.7	)	$	224.2		$	603.8

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
Conversion of subordinated units to common units		—			(52.1	)					52.1			—			—			—			—
Distributions		—			(31.7	)		—			(2.1	)		(6.4	)		—			(4.9	)		(45.1	)
Contributions from DCP Midstream, LLC		—			0.7			—			—			—			—			—			0.7
Contributions from noncontrolling interests		—			—			—			—			—			—			50.3			50.3
Other		—			(0.1	)		—			—			—			—			—			(0.1	)
Issuance of 3,500,000 Class D units		—			—			49.7			—			—			—			—			49.7
Acquisition of additional 25.1% interest in East Texas and the NGL Hedge		(68.0	)		—			4.6			—			—			—			—			(63.4	)
Deficit purchase price over acquired assets		—			—			18.3			—			—			—			—			18.3

Comprehensive income (loss):
Net loss attributable to predecessor operations		(1.0	)		—			—			—			—			—			—			(1.0	)
Net (loss) income		—			(25.3	)		(4.9	)		4.6			5.6			—			0.8			(19.2	)
Reclassification of cash flow hedges into earnings		—			—			—			—			—			9.2			—			9.2
Net unrealized gains on cash flow hedges		—			—			—			—			—			0.3			—			0.3

Total comprehensive (loss) income		(1.0	)		(25.3	)		(4.9	)		4.6			5.6			9.5			0.8			(10.7	)

Balance, June 30, 2009	$	—		$	320.5		$	67.7		$	—		$	(5.6	)	$	(31.0	)	$	213.9		$	565.5

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Description of Business and Basis of Presentation

DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we or our, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, transporting, storing and selling propane; and producing, 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; 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 us.

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. Because the additional interest in East Texas was acquired from DCP Midstream, LLC, this transaction was considered to be 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.

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 and six months ended June 30, 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 consolidated 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%. In addition, as part of this transaction we paid Delta’s unpaid capital calls to Collbran of $2.4 million. We may pay an additional $2.0 million of contingent consideration to Delta depending on if Delta meets certain throughput volume thresholds by June 30, 2011, pursuant to a gathering agreement. As of March 31, 2010 we recognized the fair value of this contingent consideration of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheet. Accordingly, we 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 represented the difference between the fair value of the consideration and the carrying value of Delta’s 5% interest. As of June 30, 2010, we have reassessed the fair value of the contingent consideration and have adjusted the fair value of the liability to approximately $0.5 million. Accordingly, we have recognized $0.5 million in other income in our condensed consolidated results of operations during the three and six months ended June 30, 2010.

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., or Buckeye, 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.

Combined Financial Information

The following table presents unaudited pro forma information for the condensed consolidated statements of operations for the three and six months ended June 30, 2010 and 2009, as if the acquisition of the Wattenberg pipeline had occurred at the beginning of each period presented. For the three and six month ended June 30, 2010, revenues of $0.9 million and $1.5 million and net income attributable to partners of $0 and $0.3 million, respectively, associated with the acquired assets, from the date of acquisition through June 30, 2010 have been included in the condensed consolidated statement of operations.


	Three Months Ended June 30, 2010								Three Months Ended June 30, 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 (a)			DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	277.5		$	—	$	277.5		$	152.0		$	3.2		$	155.2
Net income (loss) attributable to partners	$	26.0		$	—	$	26.0		$	(42.1	)	$	(70.6	)	$	(112.7	)
Less:
General partner unitholders interest in net income or loss		(4.2	)		—		(4.2	)		(2.7	)		0.8			(1.9	)

Net income (loss) allocable to limited partners	$	21.8		$	—	$	21.8		$	(44.8	)	$	(69.8	)	$	(114.6	)

Net income (loss) per limited partner unit – basic and diluted	$	0.63		$	—	$	0.63		$	(1.41	)	$	(2.21	)	$	(3.62	)

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Six Months Ended June 30, 2010								Six Months Ended June 30, 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 (a)			DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	681.2		$	0.2	$	684.4		$	436.4		$	6.5		$	442.9
Net income (loss) attributable to partners	$	51.8		$	0.1	$	51.9		$	(21.0	)	$	(68.6	)	$	(89.6	)
Less:
Net loss attributable to predecessor operations		—			—		—			1.0			—			1.0
General partner unitholders interest in net income or loss		(8.0	)		—		(8.0	)		(5.9	)		0.8			(5.1	)

Net income (loss) allocable to limited partners	$	43.8		$	0.1	$	43.9		$	(25.9	)	$	(67.8	)	$	(93.7	)

Net income (loss) per limited partner unit – basic and diluted	$	1.27		$	—	$	1.27		$	(0.86	)	$	(2.26	)	$	(3.12	)

(a)

During the second quarter of 2009, prior to our ownership, Buckeye received notification that several of its shippers on the Wattenberg pipeline intended to migrate to a competing pipeline which had recently been put into service. The notification by the shippers was accompanied by a significant decline in shipment volumes as compared to historical averages. As a result Buckeye recognized an impairment charge of $72.5 million in relation to the Wattenberg pipeline.

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 $2.4 million for three months ended June 30, 2010 and 2009, respectively and $4.9 million and $4.8 million for the six months ended June 30, 2010 and 2009, respectively, for all fees under the Omnibus Agreement.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. East Texas incurred $1.9 million and $2.2 million for the three months ended June 30, 2010 and 2009, respectively and $3.9 million and $4.4 million for the six months ended June 30, 2010 and 2009, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

In addition to the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC of $0.5 million and $0.5 million for the three months ended June 30, 2010 and 2009, respectively and $0.8 million and $1.2 million for the six months ended June 30, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Other Agreements and Transactions with DCP Midstream, LLC

On June 30, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $1.6 million, for net proceeds of $2.2 million. The surplus equipment is the result of our integration efforts and synergies realized following our acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company in November 2009. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of June 30, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our condensed consolidated balance sheets. In addition, we have recorded a deferred credit of $2.2 million in other current liabilities in our condensed consolidated balance sheets.

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.

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 expenditures on 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 $9.1 million and $46.7 million for the six months ended June 30, 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, included in our Northern Louisiana 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 Southern Oklahoma system, which is part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

for adjustments to those fees based upon plant efficiencies related to our portion of volumes from our Southern Oklahoma 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 $108.0 million as of June 30, 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 $65.0 million of these outstanding guarantees

DCP Midstream, LLC has issued parental guarantees for its 49.9% limited liability company interest in East Texas, totaling $5.5 million as of June 30, 2010, in favor of certain counterparties to processing and transportation agreements at East Texas. Concurrently, we issued similar guarantees for our 50.1% interest.

DCP Midstream, LLC was a significant customer during the three and six months ended June 30, 2010 and 2009.

Spectra Energy

We have a propane supply agreement with Spectra Energy, effective from May 1, 2008 through April 30, 2012, 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. On June 15, 2010, we entered into an amendment to the supply agreement to shorten the term of the agreement by two years to April 30, 2012, which previously terminated on April 30, 2014. In consideration for shortening the term, Spectra Energy provided us with a cash payment of $3.0 million, which we have recognized in other income — affiliates, in our Wholesale Propane Logistics segment, in the condensed consolidated statements of operations.

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 $0.2 million and $0.7 million of capital reimbursements during the six months ended June 30, 2010 and 2009, respectively.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	131.9		$	101.3		$	265.5		$	201.1
Transportation, processing and other	$	2.7		$	1.4		$	6.5		$	2.6
Purchases of natural gas, propane and NGLs	$	23.7		$	19.3		$	86.5		$	62.4
Losses from commodity derivative activity, net	$	(0.3	)	$	(1.9	)	$	(0.3	)	$	(2.6	)
General and administrative expense	$	4.8		$	5.1		$	9.6		$	10.4
Interest expense	$	0.1		$	—		$	0.2		$	0.1
Spectra Energy:
Transportation, processing and other	$	0.2		$	0.2		$	0.2		$	0.2
Purchases of natural gas, propane and NGLs	$	2.3		$	14.5		$	76.4		$	48.1
Other income	$	3.0		$	—		$	3.0		$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	2.9		$	0.6		$	4.3		$	0.7
Transportation, processing and other	$	2.0		$	1.9		$	3.9		$	4.3
Purchases of natural gas, propane and NGLs	$	1.6		$	3.9		$	3.6		$	5.9
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:


	June 30, 2010			December 31, 2009
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	57.9		$	71.5
Accounts payable	$	16.8		$	24.4
Other current liabilities	$	2.2		$	—
Unrealized gains on derivative instruments—current	$	0.3		$	5.5
Unrealized losses on derivative instruments—current	$	(0.6	)	$	(5.4	)
Spectra Energy:
Accounts receivable	$	0.1		$	0.1
Accounts payable	$	2.0		$	16.6
ConocoPhillips:
Accounts receivable	$	3.0		$	2.2
Accounts payable	$	0.5		$	2.1

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	June 30, 2010			December 31, 2009
		(Millions)
Gathering systems	15 — 30 Years	$	691.4		$	683.0
Processing plants	25 — 30 Years		436.7			427.4
Terminals	25 — 30 Years		29.1			28.9
Transportation	25 — 30 Years		239.4			217.2
General plant	3 — 5 Years		16.5			15.2
Other	20 — 50 Years		0.1			0.1
Construction work in progress			23.8			21.8

Property, plant and equipment			1,437.0			1,393.6
Accumulated depreciation			(428.5	)		(393.5	)

Property, plant and equipment, net		$	1,008.5		$	1,000.1

Interest capitalized on construction projects for the six months ended June 30, 2010 was $0 and for the year ended December 31, 2009 was $1.3 million.

Depreciation expense was $18.0 million and $15.6 million for the three months ended June 30, 2010 and 2009, respectively and $35.0 million and $29.6 million for the six months ended June 30, 2010 and 2009, respectively.

6.	Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:


	Percentage of Ownership as of June 30, 2010 and December 31, 2009		Carrying Value as of
			Carrying Value as of
			June 30, 2010		December 31, 2009
			(Millions)
Discovery Producer Services LLC	40	%	$	103.2	$	108.2
Black Lake Pipe Line Company	45	%		6.4		6.2
Other	50	%		0.2		0.2

Total investments in unconsolidated affiliates			$	109.8	$	114.6

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $36.3 million and $37.6 million at June 30, 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 June 30, 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(Millions)
Discovery Producer Services LLC	$	6.3	$	3.3	$	13.7	$	1.8
Black Lake Pipe Line Company and other		0.3		0.4		0.8		0.8

Total earnings from unconsolidated affiliates	$	6.6	$	3.7	$	14.5	$	2.6

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(Millions)
Statements of operations:
Operating revenue	$	50.5	$	40.4	$	112.1	$	61.9
Operating expenses	$	35.9	$	32.9	$	79.4	$	58.8
Net income	$	14.7	$	7.5	$	32.7	$	2.9


	June 30, 2010			December 31, 2009
	(Millions)
Balance sheets:
Current assets	$	32.5		$	41.8
Long-term assets		380.9			383.8
Current liabilities		(18.8	)		(17.4	)
Long-term liabilities		(24.6	)		(23.6	)

Net assets	$	370.0		$	384.6

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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

•

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 for identical assets or liabilities in active markets.

•

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

•

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

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

Commodity Derivative Assets and Liabilities

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

Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

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. Restricted investments have been used as collateral to secure the term loan portion of our credit facility. As of June 30, 2010, we held no short-term or restricted investments, as a result of the term loan facility being fully repaid during the first quarter of 2010.

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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

We utilize fair value on a recurring basis to measure our contingent consideration that is a result of certain acquisitions. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

The following table presents the financial instruments carried at fair value as of June 30, 2010 and December 31, 2009, by consolidated balance sheet caption and by valuation hierarchy as described above:


	June 30, 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)	$	—	$	2.0		$	0.8		$	2.8		$	—	$	6.9		$	0.4		$	7.3
Long-term assets:
Restricted investments	$	—	$	—		$	—		$	—		$	—	$	10.0		$	—		$	10.0
Commodity derivatives (c)	$	—	$	3.4		$	1.8		$	5.2		$	—	$	1.8		$	0.2		$	2.0
Current liabilities:
Acquisition related contingent consideration (d)	$	—	$	—		$	(0.5	)	$	(0.5	)	$	—	$	—		$	—		$	—
Commodity derivatives (e)	$	—	$	(11.1	)	$	(0.1	)	$	(11.2	)	$	—	$	(20.3	)	$	(0.8	)	$	(21.1	)
Interest rate derivatives (e)	$	—	$	(19.1	)	$	—		$	(19.1	)	$	—	$	(20.4	)	$	—		$	(20.4	)
Long-term liabilities (f):
Commodity derivatives	$	—	$	(24.3	)	$	(0.2	)	$	(24.5	)	$	—	$	(46.0	)	$	(0.4	)	$	(46.4	)
Interest rate derivatives	$	—	$	(14.9	)	$	—		$	(14.9	)	$	—	$	(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 other current liabilities in our condensed consolidated balance sheets

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

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

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 movements 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 June 30, 2010:
Beginning balance	$	1.5		$	1.2		$	(0.3	)	$	(0.4	)
Net realized and unrealized gains (losses) included in earnings		—			0.6			0.2			0.2
Transfers into Level 3 (a)		—			—			—			—
Transfers out of Level 3 (a)		—			—			—			—
Purchases, Issuances and Settlements net		(0.7	)		—			—			—

Ending balance	$	0.8		$	1.8		$	(0.1	)	$	(0.2	)

Net unrealized (losses) gains still held included in earnings (b)	$	(0.1	)	$	0.7		$	—		$	0.1

Three months ended June 30, 2009:
Beginning balance	$	1.0		$	1.7		$	—		$	(0.3	)
Net realized and unrealized gains (losses) included in earnings		(3.3	)		(1.7	)		(0.1	)		(0.6	)
Net transfers in (out) of Level 3 (c)		—			—			—			—
Purchases, Issuances and Settlements net		3.5			—			—			—

Ending balance	$	1.2		$	—		$	(0.1	)	$	(0.9	)

Net unrealized losses still held included in earnings (b)	$	(2.6	)	$	(1.7	)	$	(0.1	)	$	(0.6	)

(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 June 30, 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(Millions)
Six months ended June 30, 2010:
Beginning balance	$	0.4		$	0.2		$	(0.8	)	$	(0.4	)
Net realized and unrealized gains (losses) included in earnings		1.0			1.6			—			0.2
Transfers into Level 3 (a)		—			—			—			—
Transfers out of Level 3 (a)		—			—			—			—
Purchases, Issuances and Settlements net		(0.6	)		—			0.7			—

Ending balance	$	0.8		$	1.8		$	(0.1	)	$	(0.2	)

Net unrealized gains still held included in earnings (b)	$	0.7		$	1.6		$	—		$	0.1

Six months ended June 30, 2009:
Beginning balance	$	0.3		$	1.7		$	—		$	—
Net realized and unrealized gains (losses) included in earnings		(2.7	)		(1.7	)		(0.1	)		(0.9	)
Net transfers in (out) of Level 3 (c)		—			—			—			—
Purchases, Issuances and Settlements net		3.6			—			—			—

Ending balance	$	1.2		$	—		$	(0.1	)	$	(0.9	)

Net unrealized losses still held included in earnings (b)	$	(2.0	)	$	(1.7	)	$	(0.1	)	$	(0.9	)

(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 June 30, 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

As of March 31, 2010, we recognized the fair value of our contingent consideration, which is classified as Level 3, in relation to our acquisition of an additional 5% interest in Collbran, from Delta, of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheets. As of June 30, 2010, we have reassessed the fair value of the contingent consideration and have adjusted the fair value of the liability to approximately $0.5 million. Accordingly we have recognized $0.5 million in other income in our condensed consolidated results of operations for the three and six months ended June 30, 2010.

During the three and six months ended June 30, 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 $596.2 million, respectively, as of June 30, 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.

Debt

Long-term debt was as follows:


	June 30, 2010		December 31, 2009
	(Millions)
Revolving credit facility, weighted-average variable interest rate of 0.92% and 0.69%, respectively, and net effective interest rate of 4.34% 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 4.34% on the $615.0 million of outstanding debt under our revolving credit facility as of June 30, 2010.

(b)	The term loan facility was fully secured by restricted investments as of December 31, 2009. The term loan was repaid during the first quarter of 2010.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Credit Agreement

We have an $850.0 million revolving credit facility that matures June 21, 2012, or the Credit Agreement.

Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.

At June 30, 2010 and December 31, 2009, we had a $0.4 million and a $0.3 million, respectively, letter 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 June 30, 2010 the available capacity under the revolving credit facility was $234.6 million.

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.

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 June 30, 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. 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

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 through June 2012, 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

•

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

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of June 30, 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 June 30, 2010, we had $35.0 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of June 30, 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 June 30, 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 $31.5 million.

As of June 30, 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 June 30, 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 $108.0 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 June 30, 2010, we had no cash collateral posted with counterparties to our commodity derivative instruments.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Summarized Derivative Information

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


	June 30, 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		(33.3	)		(31.1	)

Total AOCI	$	(33.7	)	$	(31.9	)

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


Balance Sheet Line Item	June 30, 2010		December 31, 2009		Balance Sheet Line Item	June 30, 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	$	(19.1	)	$	(20.4	)
Unrealized gains on derivative instruments – long term		—		—	Unrealized losses on derivative instruments – long term		(14.9	)		(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	$	2.8	$	7.3	Unrealized losses on derivative instruments – current	$	(11.2	)	$	(21.1	)
Unrealized gains on derivative instruments – long term		5.2		2.0	Unrealized losses on derivative instruments – long term		(24.5	)		(46.4	)

	$	8.0	$	9.3		$	(35.7	)	$	(67.5	)

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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					Loss Reclassified From AOCI to Earnings — Effective Portion						Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing
	Three Months Ended June 30,
	2010			2009		2010			2009			2010		2009
	(Millions)					(Millions)						(Millions)
Interest rate derivatives	$	(5.8	)	$	4.8	$	(5.6	)	$	(4.6	) (a)	$	—	$	—	(a)(c)
Commodity derivatives	$	—		$	—	$	—		$	(0.1	) (b)	$	—	$	—	(b)(c)

(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 June 30, 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.


	Gain (Loss) Recognized in AOCI on Derivatives — Effective Portion					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
	Six Months Ended June 30,
	2010			2009		2010			2009			2010		2009
	(Millions)					(Millions)						(Millions)					(Millions)
Interest rate derivatives	$	(13.4	)	$	0.3	$	(11.2	)	$	(8.6	) (a)	$	—	$	—	(a)(c)	$	(18.4	)
Commodity derivatives	$	—		$	—	$	(0.4	)	$	(0.6	) (b)	$	—	$	—	(b)(c)	$	(0.3	)

(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 six months ended June 30, 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.

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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Millions)
Third party:
Realized	$	—		$	7.9		$	(2.1	)	$	14.8
Unrealized		22.8			(51.9	)		30.9			(51.1	)

Gains (losses) from commodity derivative activity, net	$	22.8		$	(44.0	)	$	28.8		$	(36.3	)

Affiliates:
Realized	$	0.2		$	0.3		$	0.1		$	(0.4	)
Unrealized		(0.5	)		(2.2	)		(0.4	)		(2.2	)

Losses from commodity derivative activity, net — affiliates	$	(0.3	)	$	(1.9	)	$	(0.3	)	$	(2.6	)

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. This table also presents our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.


	June 30, 2010
	Crude Oil		Natural Gas		Natural Gas Basis Swaps
Year of Expiration	Net Long (Short) Position (Bbls)		Net Long (Short) Position (MMBtu)		Net Long (Short) Position (MMBtu)
2010	(490,360	)	(926,100	)	(184,000	)
2011	(949,000	)	(693,500	)	(292,000	)
2012	(777,750	)	(695,400	)	(292,800	)
2013	(748,250	)	(292,000	)	(292,000	)
2014	(456,250	)	—		—
2015	(182,500	)	—		—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of June 30, 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.

On May 26, 2010, we filed a universal shelf registration statement on Form S-3 with the SEC with a maximum aggregate offering price of $1.5 billion, to replace an existing shelf registration statement. The universal shelf registration statement will allow us to register and issue additional partnership units and debt securities.

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 upon exercise of their overallotment option. We received proceeds of $69.5 million, net of offering costs.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP Midstream, LLC in consideration for an additional 25.1% interest in East Texas and a fixed price natural gas liquids derivative by NGL component for the period April 2009 to March 2010. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

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 June 30, 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 the Distributions 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.

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)
May 14, 2010	$	0.600	$	24.6
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.

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation arose from a commercial dispute involving the construction of our Wilbreeze pipeline in 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. In June 2010, we settled this matter with Driver for $0.3 million, which we have recorded to general and administrative expense during the three and six months ended June 30, 2010.

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 2010 for the 2010-2011 insurance year. We contract with third-party and affiliate insurers for: (1) automobile liability insurance for owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of all real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay in the 2010-2011 insurance year compared with the 2009-2010 insurance year. We are jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. 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 2010-2011 insurance year covers onshore named windstorm property and business interruption insurance and onshore and offshore non-windstorm property and business interruption insurance. The availability of offshore named windstorm property and business interruption insurance has been significantly reduced over the past two years as a result of higher industry-wide damage claims. Additionally, the named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, higher deductibles and lower coverage limits. Consequently, as with the 2009-2010 insurance year, Discovery elected to not purchase offshore named windstorm property and business interruption insurance coverage for the 2010-2011 insurance year.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Indemnification — DCP Midstream, LLC has agreed to indemnify 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.

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 June 30, 2010


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenue	$	211.7		$	62.2		$	3.6		$	—		$	277.5

Gross margin (a)	$	70.2		$	(0.9	)	$	2.5		$	—		$	71.8
Operating and maintenance expense		(17.0	)		(2.6	)		(1.0	)		—			(20.6	)
Depreciation and amortization expense		(17.8	)		(0.3	)		(0.6	)		—			(18.7	)
General and administrative expense		—			—			—			(8.2	)		(8.2	)
Other income		0.5			—			—			—			0.5
Other income — affiliates		—			3.0			—			—			3.0
Earnings from unconsolidated affiliates		6.3			—			0.3			—			6.6
Interest expense		—			—			—			(7.3	)		(7.3	)
Income tax expense (b)		—			—			—			(0.1	)		(0.1	)

Net income (loss)		42.2			(0.8	)		1.2			(15.6	)		27.0
Net income attributable to noncontrolling interests		(1.0	)		—			—			—			(1.0	)

Net income (loss) attributable to partners	$	41.2		$	(0.8	)	$	1.2		$	(15.6	)	$	26.0

Non-cash derivative mark-to-market (c)	$	22.3		$	—		$	—		$	0.2		$	22.5

Capital expenditures	$	11.2		$	—		$	2.0		$	—		$	13.2

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Three Months Ended June 30, 2009


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenue	$	103.3		$	46.9		$	1.8		$	—		$	152.0

Gross margin (a)	$	(3.4	)	$	5.8		$	1.3		$	—		$	3.7
Operating and maintenance expense		(14.5	)		(2.4	)		(0.2	)		—			(17.1	)
Depreciation and amortization expense		(15.4	)		(0.4	)		(0.4	)		(0.1	)		(16.3	)
General and administrative expense		—			—			—			(7.1	)		(7.1	)
Earnings from unconsolidated affiliates		3.3			—			0.4			—			3.7
Interest income		—			—			—			0.1			0.1
Interest expense		—			—			—			(7.0	)		(7.0	)
Income tax expense (b)		—			—			—			—			—

Net (loss) income		(30.0	)		3.0			1.1			(14.1	)		(40.0	)
Net income attributable to noncontrolling interests		(2.1	)		—			—			—			(2.1	)

Net (loss) income attributable to partners	$	(32.1	)	$	3.0		$	1.1		$	(14.1	)	$	(42.1	)

Non-cash derivative mark-to-market (c)	$	(54.0	)	$	(0.1	)	$	—		$	(0.1	)	$	(54.2	)

Capital expenditures	$	62.1		$	0.3		$	—		$	—		$	62.4

Investments in unconsolidated affiliates	$	5.6		$	—		$	—		$	—		$	5.6

Six Months Ended June 30, 2010


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenue	$	429.8		$	243.0		$	8.4		$	—		$	681.2

Gross margin (a)	$	124.0		$	12.8		$	5.9		$	—		$	142.7
Operating and maintenance expense		(33.2	)		(5.2	)		(1.2	)		—			(39.6	)
Depreciation and amortization expense		(34.8	)		(0.6	)		(1.1	)		—			(36.5	)
General and administrative expense		—			—			—			(16.8	)		(16.8	)
Other income		0.5			—			—			—			0.5
Other income — affiliates		—			3.0			—			—			3.0
Earnings from unconsolidated affiliates		13.7			—			0.8			—			14.5
Interest expense		—			—			—			(14.5	)		(14.5	)
Income tax expense (b)		—			—			—			(0.4	)		(0.4	)

Net income (loss)		70.2			10.0			4.4			(31.7	)		52.9
Net income attributable to noncontrolling interests		(1.1	)		—			—			—			(1.1	)

Net income (loss) attributable to partners	$	69.1		$	10.0		$	4.4		$	(31.7	)	$	51.8

Non-cash derivative mark-to-market (c)	$	30.7		$	(0.6	)	$	—		$	0.2		$	30.3

Capital expenditures	$	23.3		$	—		$	2.1		$	—		$	25.4

Acquisitions, net of cash acquired	$	—		$	—		$	22.0		$	—		$	22.0

Investments in unconsolidated affiliates	$	0.7		$	—		$	—		$	—		$	0.7

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Six Months Ended June 30, 2009


	Natural Gas Services			Wholesale Propane Logistics			NGL Logistics			Other			Total
	(Millions)
Total operating revenue	$	253.1		$	179.7		$	3.6		$	—		$	436.4

Gross margin (a)	$	37.0		$	31.6		$	2.6		$	—		$	71.2
Operating and maintenance expense		(27.7	)		(5.1	)		(0.5	)		—			(33.3	)
Depreciation and amortization expense		(29.3	)		(0.7	)		(0.8	)		(0.1	)		(30.9	)
General and administrative expense		—			—			—			(15.7	)		(15.7	)
Earnings from unconsolidated affiliates		1.8			—			0.8			—			2.6
Interest income		—			—			—			0.3			0.3
Interest expense		—			—			—			(14.3	)		(14.3	)
Income tax expense (b)		—			—			—			(0.1	)		(0.1	)

Net (loss) income		(18.2	)		25.8			2.1			(29.9	)		(20.2	)
Net income attributable to noncontrolling interests		(0.8	)		—			—			—			(0.8	)

Net (loss) income attributable to partners	$	(19.0	)	$	25.8		$	2.1		$	(29.9	)	$	(21.0	)

Non-cash derivative mark-to-market (c)	$	(53.9	)	$	0.1		$	—		$	(0.2	)	$	(54.0	)

Capital expenditures	$	118.0		$	0.4		$	—		$	—		$	118.4

Acquisitions, net of cash acquired	$	0.1		$	—		$	—		$	—		$	0.1

Investments in unconsolidated affiliates	$	5.8		$	—		$	—		$	—		$	5.8


	June 30, 2010		December 31, 2009
	(Millions)
Segment long-term assets:
Natural Gas Services	$	1,163.3	$	1,185.2
Wholesale Propane Logistics		52.3		53.2
NGL Logistics (d)		56.7		32.3
Other (e)		6.2		13.1

Total long-term assets		1,278.5		1,283.8
Current assets		134.7		197.7

Total assets	$	1,413.2	$	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.

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


	Six Months Ended June 30,
	2010		2009
	(Millions)
Cash paid for interest, net of amounts capitalized	$	3.2	$	6.2
Cash paid for income taxes, net of income tax refunds	$	0.5	$	0.5

Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	3.2	$	18.7
Other non-cash additions of property plant and equipment	$	0.2	$	1.8
Acquisition related contingent consideration	$	1.0	$	—

14.

Supplementary Information — Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a wholly owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream Partners, LP’s results on a consolidated basis. In conjunction with the universal shelf registration statement on Form S-3 filed with the SEC on May 26, 2010, the parent guarantor has agreed to fully and unconditionally guarantee securities of the subsidiary issuer that may be issued in future periods. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Balance Sheets June 30, 2010
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	1.7		$	4.8		$	(1.7	)	$	4.8
Accounts receivable		—		—			104.4			—			104.4
Inventories		—		—			19.6			—			19.6
Other		—		—			5.9			—			5.9

Total current assets		—		1.7			134.7			(1.7	)		134.7
Property, plant and equipment, net		—		—			1,008.5			—			1,008.5
Goodwill and intangible assets, net		—		—			151.0			—			151.0
Advances receivable — consolidated subsidiaries		196.7		517.6			—			(714.3	)		—
Investments in consolidated subsidiaries		182.9		313.0			—			(495.9	)		—
Investments in unconsolidated affiliates		—		—			109.8			—			109.8
Other long term assets		—		0.4			8.8			—			9.2

Total assets	$	379.6	$	832.7		$	1,412.8		$	(1,211.9	)	$	1,413.2

LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19.9		$	122.6		$	(1.7	)	$	140.8
Advances payable — consolidated subsidiaries		—		—			714.3			(714.3	)		—
Long-term debt		—		615.0			—			—			615.0
Other long-term liabilities		—		14.9			38.7			—			53.6

Total liabilities		—		649.8			875.6			(716.0	)		809.4


Commitments and contingent liabilities

Equity:
Partners’ equity
Net equity		379.6		216.2			313.4			(495.9	)		413.3
Accumulated other comprehensive loss		—		(33.3	)		(0.4	)		—			(33.7	)

Total partners’ equity		379.6		182.9			313.0			(495.9	)		379.6
Noncontrolling interests		—		—			224.2			—			224.2

Total equity		379.6		182.9			537.2			(495.9	)		603.8

Total liabilities and equity	$	379.6	$	832.7		$	1,412.8		$	(1,211.9	)	$	1,413.2

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Balance Sheets December 31, 2009
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	1.6		$	1.3		$	(0.8	)	$	2.1
Accounts receivable		—		—			152.5			—			152.5
Inventories		—		—			34.2			—			34.2
Other		—		0.1			8.8			—			8.9

Total current assets		—		1.7			196.8			(0.8	)		197.7
Restricted investments		—		10.0			—			—			10.0
Property, plant and equipment, net		—		—			1,000.1			—			1,000.1
Goodwill and intangible assets, net		—		—			152.6			—			152.6
Advances receivable — consolidated subsidiaries		245.8		520.0			—			(765.8	)		—
Investments in consolidated subsidiaries		131.9		245.3			—			(377.2	)		—
Investments in unconsolidated affiliates		—		—			114.6			—			114.6
Other long-term assets		—		0.6			5.9			—			6.5

Total assets	$	377.7	$	777.6		$	1,470.0		$	(1,143.8	)	$	1,481.5

LIABILITIES AND EQUITY

Accounts payable and other current liabilities	$	—	$	21.1		$	170.8		$	(0.8	)	$	191.1
Advances payable — consolidated subsidiaries		—		—			765.8			(765.8	)		—
Long-term debt		—		613.0			—			—			613.0
Other long-term liabilities		—		11.6			60.4			—			72.0

Total liabilities		—		645.7			997.0			(766.6	)		876.1


Commitments and contingent liabilities

Equity:
Partners’ equity
Net equity		377.7		163.0			246.1			(377.2	)		409.6
Accumulated other comprehensive loss		—		(31.1	)		(0.8	)		—			(31.9	)

Total partners’ equity		377.7		131.9			245.3			(377.2	)		377.7
Noncontrolling interests		—		—			227.7			—			227.7

Total equity		377.7		131.9			473.0			(377.2	)		605.4

Total liabilities and equity	$	377.7	$	777.6		$	1,470.0		$	(1,143.8	)	$	1,481.5

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Operations Three Months Ended June 30, 2010
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	228.0		$	—		$	228.0
Transportation, processing and other		—		—			27.0			—			27.0
Gains from commodity derivative activity, net		—		—			22.5			—			22.5

Total operating revenues		—		—			277.5			—			277.5

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			(205.7	)		—			(205.7	)
Operating and maintenance expense		—		—			(20.6	)		—			(20.6	)
Depreciation and amortization expense		—		—			(18.7	)		—			(18.7	)
General and administrative expense		—		—			(8.2	)		—			(8.2	)
Other income		—		—			0.5			—			0.5
Other income — affiliates		—		—			3.0			—			3.0

Total operating costs and expenses		—		—			(249.7	)		—			(249.7	)

Operating income		—		—			27.8			—			27.8
Interest expense, net		—		(7.3	)		—			—			(7.3	)
Earnings from consolidated subsidiaries		26.0		33.3			—			(59.3	)		—
Earnings from unconsolidated affiliates		—		—			6.6			—			6.6

Income before income taxes		26.0		26.0			34.4			(59.3	)		27.1
Income tax expense		—		—			(0.1	)		—			(0.1	)

Net income		26.0		26.0			34.3			(59.3	)		27.0
Net income attributable to noncontrolling interests		—		—			(1.0	)		—			(1.0	)

Net income attributable to partners	$	26.0	$	26.0		$	33.3		$	(59.3	)	$	26.0

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Operations Three Months Ended June 30, 2009
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—		$	—		$	173.7		$	—	$	173.7
Transportation, processing and other		—			—			24.2			—		24.2
Gains from commodity derivative activity, net		—			—			(45.9	)		—		(45.9	)

Total operating revenues		—			—			152.0			—		152.0

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—			—			(148.3	)		—		(148.3	)
Operating and maintenance expense		—			—			(17.1	)		—		(17.1	)
Depreciation and amortization expense		—			—			(16.3	)		—		(16.3	)
General and administrative expense		—			—			(7.1	)		—		(7.1	)

Total operating costs and expenses		—			—			(188.8	)		—		(188.8	)

Operating loss		—			—			(36.8	)		—		(36.8	)
Interest expense, net		—			(6.9	)		—			—		(6.9	)
Losses from consolidated subsidiaries		(42.1	)		(35.2	)		—			77.3		—
Earnings from unconsolidated affiliates		—			—			3.7			—		3.7

Net income		(42.1	)		(42.1	)		(33.1	)		77.3		(40.0	)
Net income attributable to noncontrolling interests		—			—			(2.1	)		—		(2.1	)

Net loss attributable to partners	$	(42.1	)	$	(42.1	)	$	(35.2	)	$	77.3	$	(42.1	)

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Operations Six Months Ended June 30, 2010
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	598.4		$	—		$	598.4
Transportation, processing and other		—		—			54.3			—			54.3
Gains from commodity derivative activity, net		—		—			28.5			—			28.5

Total operating revenues		—		—			681.2			—			681.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			(538.5	)		—			(538.5	)
Operating and maintenance expense		—		—			(39.6	)		—			(39.6	)
Depreciation and amortization expense		—		—			(36.5	)		—			(36.5	)
General and administrative expense		—		—			(16.8	)		—			(16.8	)
Other income		—		—			0.5			—			0.5
Other income — affiliates		—		—			3.0			—			3.0

Total operating costs and expenses		—		—			(627.9	)		—			(627.9	)

Operating income		—		—			53.3			—			53.3
Interest expense, net		—		(14.4	)		(0.1	)		—			(14.5	)
Earnings from consolidated subsidiaries		51.8		66.2			—			(118.0	)		—
Earnings from unconsolidated affiliates		—		—			14.5			—			14.5

Income before income taxes		51.8		51.8			67.7			(118.0	)		53.3
Income tax expense		—		—			(0.4	)		—			(0.4	)

Net income		51.8		51.8			67.3			(118.0	)		52.9
Net income attributable to noncontrolling interests		—		—			(1.1	)		—			(1.1	)

Net income attributable to partners	$	51.8	$	51.8		$	66.2		$	(118.0	)	$	51.8

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Operations Six Months Ended June 30, 2009
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—		$	—		$	430.8		$	—	$	430.8
Transportation, processing and other		—			—			44.5			—		44.5
Losses from commodity derivative activity, net		—			—			(38.9	)		—		(38.9	)

Total operating revenues		—			—			436.4			—		436.4

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—			—			(365.2	)		—		(365.2	)
Operating and maintenance expense		—			—			(33.3	)		—		(33.3	)
Depreciation and amortization expense		—			—			(30.9	)		—		(30.9	)
General and administrative expense		—			—			(15.7	)		—		(15.7	)

Total operating costs and expenses		—			—			(445.1	)		—		(445.1	)

Operating loss		—			—			(8.7	)		—		(8.7	)
Interest expense, net		—			(13.9	)		(0.1	)		—		(14.0	)
Losses from consolidated subsidiaries		(21.0	)		(7.1	)		—			28.1		—
Earnings from unconsolidated affiliates		—			—			2.6			—		2.6

Income before income taxes		(21.0	)		(21.0	)		(6.2	)		28.1		(20.1	)
Income tax expense		—			—			(0.1	)		—		(0.1	)

Net loss		(21.0	)		(21.0	)		(6.3	)		28.1		(20.2	)
Net income attributable to noncontrolling interests		—			—			(0.8	)		—		(0.8	)

Net loss attributable to partners	$	(21.0	)	$	(21.0	)	$	(7.1	)	$	28.1	$	(21.0	)

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Cash Flows Six Months Ended June 30, 2010
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES

Net cash provided by (used in) operating activities	$	49.1		$	(12.0	)	$	52.5		$	(0.9	)	$	88.7

INVESTING ACTIVITIES:
Capital expenditures		—			—			(25.4	)		—			(25.4	)
Acquisitions, net of cash acquired		—			—			(22.0	)		—			(22.0	)
Investments in unconsolidated affiliates		—			—			(0.7	)		—			(0.7	)
Proceeds from sale of assets		—			—			1.7			—			1.7
Proceeds from sales of available-for-sale securities		—			10.1			—			—			10.1

Net cash provided by (used in) investing activities		—			10.1			(46.4	)		—			(36.3	)

FINANCING ACTIVITIES:
Proceeds from debt		—			210.6			—			—			210.6
Payments of debt		—			(208.6	)		—			—			(208.6	)
Distributions to unitholders and general partner		(49.1	)		—			—			—			(49.1	)
Distributions to noncontrolling interests		—			—			(8.2	)		—			(8.2	)
Contributions from noncontrolling interests		—			—			9.1			—			9.1
Purchase of additional interest in a subsidiary		—			—			(3.5	)		—			(3.5	)

Net cash (used in) provided by financing activities		(49.1	)		2.0			(2.6	)		—			(49.7	)

Net change in cash and cash equivalents		—			0.1			3.5			(0.9	)		2.7
Cash and cash equivalents, beginning of period		—			1.6			1.3			(0.8	)		2.1

Cash and cash equivalents, end of period	$	—		$	1.7		$	4.8		$	(1.7	)	$	4.8

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Condensed Consolidating Statements of Cash Flows Six Months Ended June 30, 2009
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES

Net cash provided by (used in) operating activities	$	40.2		$	(31.7	)	$	42.9		$	(0.1	)	$	51.3

INVESTING ACTIVITIES:
Capital expenditures		—			—			(118.4	)		—			(118.4	)
Acquisitions, net of cash acquired		—			—			(0.1	)		—			(0.1	)
Investments in unconsolidated affiliates		—			—			(5.8	)		—			(5.8	)
Proceeds from sale of assets		—			—			0.3			—			0.3
Purchase of available-for-sale securities		—			(1.1	)		—			—			(1.1	)
Proceeds from sales of available-for-sale securities		—			26.1			—			—			26.1

Net cash provided by (used in) investing activities		—			25.0			(124.0	)		—			(99.0	)

FINANCING ACTIVITIES:
Proceeds from debt		—			68.3			—			—			68.3
Payments of debt		—			(86.8	)		—			—			(86.8	)
Net change in advances to predecessor from DCP Midstream, LLC		—			—			3.0			—			3.0
Distributions to unitholders and general partner		(40.2	)		—			—			—			(40.2	)
Distributions to noncontrolling interests		—			—			(4.9	)		—			(4.9	)
Contributions from noncontrolling interests		—			—			50.3			—			50.3
Contributions from DCP Midstream, LLC		—			—			0.7			—			0.7

Net cash (used in) provided by financing activities		(40.2	)		(18.5	)		49.1			—			(9.6	)

Net change in cash and cash equivalents		—			(25.2	)		(32.0	)		(0.1	)		(57.3	)
Cash and cash equivalents, beginning of period		—			26.6			35.6			(0.3	)		61.9

Cash and cash equivalents, end of period	$	—		$	1.4		$	3.6		$	(0.4	)	$	4.6

15. Subsequent Events

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

On July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, for $15.0 million in cash, financed with borrowings under our revolving credit facility, bringing our ownership interest to 100%. Prior to our acquisition of an additional 50% interest in Black Lake from an affiliate of BP PLC, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we will account for Black Lake as a consolidated subsidiary.

On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC for $1.5 million in cash, financed with borrowings under our revolving credit facility, in a transaction among entities under common control.

The results of Atlantic Energy’s assets will be included prospectively from the date of acquisition in our Wholesale Propane Logistics segment. The results of our additional 50% interest in Black Lake will be included prospectively from the date of acquisition in our NGL Logistics segment. Given the recent timing of these acquisitions, we have not completed the initial accounting for the Black Lake and Atlantic Energy business combinations and we have not made certain disclosures. These disclosures include the fair value of assets acquired and liabilities assumed, intangible asset classifications, and pro-forma information. The initial accounting and related disclosures required for business combinations will be made in a subsequent filing.

On July 27, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.61 per unit, payable on August 13, 2010 to unitholders of record on August 6, 2010.

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.

In 2010 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 shut downs and producer wellhead freeze offs.

During the second quarter we had a planned outage related to our Providence wholesale propane terminal, which along with warmer weather and an early spring, tempered propane sales volumes. This was partially offset by the cash payment we received in conjunction with an amendment to an existing propane supply contract.

Improvements in the business environment along with opportunities in the market enabled us to continue to execute on our growth objectives in 2010 through a series of fee-based acquisitions and capital projects around our existing footprint. In January, we completed an acquisition of our Wattenberg fee-based NGL pipeline and announced a related expansion capital project. In July we acquired an additional 55% interest in our Black Lake fee-based NGL pipeline, bringing our ownership interest in Black Lake to 100%. In July, we also closed on an acquisition which expanded our existing northeast U.S. wholesale propane logistics business into the mid-Atlantic region through the addition of a marine import terminal and storage facility in the Port of Chesapeake, Virginia.

In conjunction with our general partner, DCP Midstream, LLC, in May we signed a non-binding letter of intent with EQT Corporation, to create a natural gas processing and related NGL infrastructure joint venture to serve EQT and third party producers in the Marcellus and Huron shale areas of the Appalachian basin. Terms and conditions of the joint venture are being finalized, and signing is expected in the third quarter of 2010.

In 2010 we plan to integrate both the Michigan gathering and treating system we acquired in November 2009, as well as the Wattenberg NGL pipeline acquisition. Our integration efforts are progressing according to plan. The Wattenberg capital expansion project, which we expect to complete in early 2011, is also progressing on plan.

Financial results for the first half of the year were in line with our previously provided 2010 forecast. In July, we announced a quarterly distribution of $0.61 per limited partner unit, which represents an increase of 1.7% over the last quarterly distribution paid. The distribution increase reflects our solid and sustainable business results as well as our recent execution on growth opportunities.

General Trends and Outlook

In 2010, our strategic objectives will continue to 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 expenditures for maintenance capital of approximately $10 million to $15 million in 2010 to maintain our existing assets. We also expect to incur expenditures for expansion capital improvements 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 acquisitions or additional investment opportunities that may be identified throughout the course of the year and approved by our management and our Board of Directors.

During the remainder of 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.

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 the first half of 2010, petrochemical demand remained 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 the remainder of 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

On July 30, 2010, we acquired Atlantic Energy, a wholly owned subsidiary of UGI Corporation, for $49.0 million plus propane inventory and other working capital of $17.3 million. Atlantic Energy has a contractual agreement with Spectra Energy, the supplier of the acquired propane inventory, in which the final price of the acquired inventory will be determined based upon index rates at established future dates. Atlantic Energy’s sales agreements specify floating pricing terms in excess of the floating pricing terms established in the contractual agreement with Spectra Energy. The acquisition was financed with borrowings under our revolving credit facility. Atlantic Energy owns and operates a marine import terminal with 20 million gallons of above ground storage in the Port of Chesapeake, Virginia. The assets serve as a supply point for propane customers in the mid-Atlantic region, and will extend our existing northeast U.S. wholesale propane business into the mid-Atlantic. This acquisition provides us with an excellent opportunity to expand our existing market position as one of the largest wholesale propane suppliers in the northeast. One of the keys to our success in the wholesale propane business has been the breadth of our supply options. The addition of the Chesapeake assets will build on our supply and logistics capabilities and help in continuing to ensure reliable deliveries to our customers.

On July 27, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.61 per unit, payable on August 13, 2010 to unitholders of record on August 6, 2010. This represents an increase of 1.7 percent over the last quarterly distribution of $0.60 per unit paid on May 14, 2010.

On June 15, 2010, we entered into an amendment to our six year propane supply agreement with Spectra Energy to shorten the term of the agreement by two years so that it will now terminate on April 30, 2012. In consideration for shortening the term Spectra Energy provided us with a cash payment of $3.0 million. The supply contract amendment provides us with additional flexibility in sourcing future supply, a direct contracting relationship with the supplier, and an acceleration of cash flow.

On June 3, 2010, our general partner announced the appointment of Jeff W. Sheets as the ConocoPhillips representative of the board of directors. ConocoPhillips owns 50% of the owner of the general partner, DCP Midstream, LLC.

On May 27, 2010, we announced along with EQT Corporation, or EQT, and DCP Midstream, LLC that we have signed a letter of intent to create a natural gas processing and related natural gas liquid, or NGL, joint venture to serve EQT and third party producers in the Marcellus and Huron shale areas of the Appalachian basin, two of the country’s most active shale plays. Under the letter of intent we, along with EQT and DCP Midstream, LLC, would pursue gas processing and related NGL infrastructure opportunities in the Marcellus and Huron shale areas through the joint venture. The joint venture will be the preferred processor of EQT’s wet gas in the Marcellus and Huron shale areas. As contemplated by the letter of intent, we and DCP Midstream, LLC, together, would contribute approximately $200 million in cash in exchange for a 50% interest in the joint venture and would operate the new joint venture. The cash would be used to fund initial expansion of the facilities to accommodate EQT and third party production growth in the Marcellus and Huron shale. EQT would contribute an equivalent value in existing assets consisting of its 170 MMcf/d natural gas processing plant and related NGL pipeline located in Southeast Kentucky serving EQT’s Huron shale production in exchange for its 50% interest in the new joint venture.

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 improvements 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.

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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Millions)
Reconciliation of Non-GAAP Measures

Reconciliation of net income (loss) attributable to partners to gross margin:

Net income (loss) attributable to partners	$	26.0		$	(42.1	)	$	51.8		$	(21.0	)
Interest expense		7.3			7.0			14.5			14.3
Income tax expense		0.1			—			0.4			0.1
Operating and maintenance expense		20.6			17.1			39.6			33.3
Depreciation and amortization expense		18.7			16.3			36.5			30.9
General and administrative expense		8.2			7.1			16.8			15.7
Other income		(0.5	)		—			(0.5	)		—
Other income — affiliates		(3.0	)		—			(3.0	)		—
Interest income		—			(0.1	)		—			(0.3	)
Earnings from unconsolidated affiliates		(6.6	)		(3.7	)		(14.5	)		(2.6	)
Net income attributable to noncontrolling interests		1.0			2.1			1.1			0.8

Gross margin	$	71.8		$	3.7		$	142.7		$	71.2

Non-cash commodity derivative mark-to-market (a)	$	22.3		$	(54.1	)	$	30.1		$	(53.8	)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			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 (loss) attributable to partners	$	41.2		$	(32.1	)	$	69.1		$	(19.0	)
Operating and maintenance expense		17.0			14.5			33.2			27.7
Depreciation and amortization expense		17.8			15.4			34.8			29.3
Other income		(0.5	)		—			(0.5	)		—
Earnings from unconsolidated affiliates		(6.3	)		(3.3	)		(13.7	)		(1.8	)
Net income attributable to noncontrolling interests		1.0			2.1			1.1			0.8

Segment gross margin	$	70.2		$	(3.4	)	$	124.0		$	37.0

Non-cash commodity derivative mark-to-market (a)	$	22.3		$	(54.0	)	$	30.7		$	(53.9	)


*Wholesale Propane Logistics segment:*
Segment net (loss) income attributable to partners	$	(0.8	)	$	3.0		$	10.0		$	25.8
Operating and maintenance expense		2.6			2.4			5.2			5.1
Depreciation and amortization expense		0.3			0.4			0.6			0.7
Other income — affiliates		(3.0	)		—			(3.0	)		—

Segment gross margin	$	(0.9	)	$	5.8		$	12.8		$	31.6

Non-cash commodity derivative mark-to-market (a)	$	—		$	(0.1	)	$	(0.6	)	$	0.1


*NGL Logistics segment:*
Segment net income attributable to partners	$	1.2		$	1.1		$	4.4		$	2.1
Operating and maintenance expense		1.0			0.2			1.2			0.5
Depreciation and amortization expense		0.6			0.4			1.1			0.8
Earnings from unconsolidated affiliates		(0.3	)		(0.4	)		(0.8	)		(0.8	)

Segment gross margin	$	2.5		$	1.3		$	5.9		$	2.6

(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.

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 and six months ended June 30, 2010 are the same as those described in our 2009 Form 10-K.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion:


	Three Months Ended June 30,						Six Months Ended June 30,						Variance Three Months 2010 vs. 2009					Variance Six Months 2010 vs. 2009
	2010 (a)(b)			2009 (b)			2010 (a)(b)			2009 (b)			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services (c)	$	211.7		$	103.3		$	429.8		$	253.1		$	108.4		105	%	$	176.7		70	%
Wholesale Propane Logistics		62.2			46.9			243.0			179.7			15.3		33	%		63.3		35	%
NGL Logistics		3.6			1.8			8.4			3.6			1.8		100	%		4.8		133	%

Total operating revenues		277.5			152.0			681.2			436.4			125.5		83	%		244.8		56	%

Gross margin (d):
Natural Gas Services		70.2			(3.4	)		124.0			37.0			73.6		*			87.0		235	%
Wholesale Propane Logistics		(0.9	)		5.8			12.8			31.6			(6.7	)	*			(18.8	)	(59	)%
NGL Logistics		2.5			1.3			5.9			2.6			1.2		92	%		3.3		127	%

Total gross margin		71.8			3.7			142.7			71.2			68.1		1,841	%		71.5		100	%
Operating and maintenance expense		(20.6	)		(17.1	)		(39.6	)		(33.3	)		3.5		20	%		6.3		19	%
Depreciation and amortization expense		(18.7	)		(16.3	)		(36.5	)		(30.9	)		2.4		15	%		5.6		18	%
General and administrative expense		(8.2	)		(7.1	)		(16.8	)		(15.7	)		1.1		15	%		1.1		7	%
Other income		0.5			—			0.5			—			0.5		100	%		0.5		100	%
Other income — affiliates		3.0			—			3.0			—			3.0		100	%		3.0		100	%
Earnings from unconsolidated affiliates (e)		6.6			3.7			14.5			2.6			2.9		78	%		11.9		458	%
Interest income		—			0.1			—			0.3			(0.1	)	(100	)%		(0.3	)	(100	)%
Interest expense		(7.3	)		(7.0	)		(14.5	)		(14.3	)		0.3		4	%		0.2		1	%
Income tax expense		(0.1	)		—			(0.4	)		(0.1	)		0.1		100	%		0.3		300	%
Net income attributable to noncontrolling interests		(1.0	)		(2.1	)		(1.1	)		(0.8	)		(1.1	)	(52	)%		0.3		38	%

Net income (loss) attributable to partners	$	26.0		$	(42.1	)	$	51.8		$	(21.0	)	$	68.1		*		$	72.8		*

Other data:
Non-cash commodity derivative mark-to-market	$	22.3		$	(54.1	)	$	30.1		$	(53.8	)	$	76.4		*		$	83.9		*
Natural gas throughput (MMcf/d) (e)		1,161			1,108			1,163			1,051			53		5	%		112		11	%
NGL gross production (Bbls/d) (e)		33,846			28,584			33,360			25,208			5,262		18	%		8,152		32	%
Propane sales volume (Bbls/d)		13,055			13,912			23,205			25,502			(857	)	(6	)%		(2,297	)	(9	)%
NGL pipelines throughput (Bbls/d) (e)		35,710			26,850			37,810			25,409			8,860		33	%		12,401		49	%

*	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)

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 June 30, 2010 vs. Three Months Ended June 30, 2009

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

•

$68.4 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $76.4 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $8.0 million due to generally higher average prices of commodities in 2010;

•

$38.5 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, and an increase in NGL production, partially offset a decrease in natural gas sales volumes across certain assets;

•

$15.0 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

•

$2.8 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 pipeline acquisitions.

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

•

$73.6 million increase for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenues section above, higher commodity prices, and increased fee-based throughput volumes resulting from the Michigan acquisition, partially offset by reduced marketing activity and natural gas volumes across certain of our assets; and

•

$1.2 million increase for our NGL Logistics segment, primarily as a result of higher volumes and per unit margins.

These increases were partially offset by:

•

$6.7 million decrease for our Wholesale Propane Logistics segment. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our Michigan integration costs and turnaround activities at certain assets, as well as our Wattenberg pipeline acquisition.

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

Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, a supplier for our Wholesale Propane Logistics segment, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

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 attributable to noncontrolling interests — Net income attributable to noncontrolling interests include the impact of turnarounds at East Texas in 2010.

Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009

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

•

$102.4 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 in the first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a fire at East Texas and our Wyoming pipeline integrity and system enhancement project;

•

$67.4 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $83.8 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $16.4 million due to generally higher average prices of commodities in 2010;

•

$63.2 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

•

$9.8 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 changes in contract mix.

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

•

$87.0 million increase for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenue section above, higher commodity prices, 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 in the first quarter. 2009 results include the first quarter impact of a fire at East Texas and operational downtime; and

•

$3.3 million increase for our NGL Logistics segment as a result of higher volumes and per unit margins.

These increases were partially offset by:

•

$18.8 million decrease for our Wholesale Propane Logistics segment. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 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.

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.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests include the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter and turnarounds at East Texas in 2010.

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 June 30,						Six Months Ended June 30,						Variance Three Months 2010 vs. 2009					Variance Six Months 2010 vs. 2009
	2010 (a)(b)			2009 (b)			2010 (a)(b)			2009 (b)			Increase (Decrease)			Percent		Increase (Decrease)		Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	165.2		$	126.5		$	352.8		$	250.2		$	38.7		31	%	$	102.6	41	%
Transportation, processing and other		24.2			22.6			48.5			41.7			1.6		7	%		6.8	16	%
Gains (losses) from commodity derivative activity (c)		22.3			(45.8	)		28.5			(38.8	)		68.1		*			67.3	*

Total operating revenues		211.7			103.3			429.8			253.1			108.4		105	%		176.7	70	%
Purchases of natural gas and NGLs		141.5			106.7			305.8			216.1			34.8		33	%		89.7	42	%

Segment gross margin (d)		70.2			(3.4	)		124.0			37.0			73.6		*			87.0	235	%
Operating and maintenance expense		(17.0	)		(14.5	)		(33.2	)		(27.7	)		2.5		17	%		5.5	20	%
Depreciation and amortization expense		(17.8	)		(15.4	)		(34.8	)		(29.3	)		2.4		16	%		5.5	19	%
Other income		0.5			—			0.5			—			0.5		100	%		0.5	100	%
Earnings from unconsolidated affiliates (e)		6.3			3.3			13.7			1.8			3.0		91	%		11.9	661	%

Segment net income (loss)		42.2			(30.0	)		70.2			(18.2	)		72.2		*			88.4	*
Segment net income attributable to noncontrolling interests		(1.0	)		(2.1	)		(1.1	)		(0.8	)		(1.1	)	(52	)%		0.3	38	%

Segment net income (loss) attributable to partners	$	41.2		$	(32.1	)	$	69.1		$	(19.0	)	$	73.3		*		$	88.1	*

Other data:
Non-cash commodity derivative mark-to-market	$	22.3		$	(54.0	)	$	30.7		$	(53.9	)	$	76.3		*		$	84.6	*
Natural gas throughput (MMcf/d) (e)		1,161			1,108			1,163			1,051			53		5	%		112	11	%
NGL gross production (Bbls/d) (e)		33,846			28,584			33,360			25,208			5,262		18	%		8,152	32	%

*	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.

(b)

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 June 30, 2010 vs. Three Months Ended June 30, 2009

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

•

$68.1 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $76.3 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $8.2 million due to generally higher average prices of commodities in 2010;

•

$37.5 million increase attributable to increased commodity prices, which impact both sales and purchases;

•

$1.6 million increase primarily as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, partially offset by decreases across certain other assets; and

•

$1.0 million increase due primarily to 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 a decrease in natural gas sales volumes across certain assets.

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:

•

$68.1 million increase related to commodity derivative activities as discussed in the Operating Revenues section above;

•

$8.6 million increase as a result of higher commodity prices; and

•

$1.6 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, partially offset by decreases across certain other assets.

These increases were partially offset by:

•

$4.9 million decrease in volumes attributable to reduced marketing activity, the impact of turnarounds and natural gas volume reductions across certain of our assets, partially offset by organic growth from our Piceance Basin expansion project.

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, due primarily to higher prices and increased NGL production, partially offset by increased plant fuel costs and higher costs and downtime related to turnarounds. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests include the impact of turnaround activity at East Texas in 2010.

Natural Gas Throughput — Natural gas transported, processed and/or treated in 2010 remained relatively constant compared to 2009. 2010 results include increased fee-based throughput volumes from our Michigan acquisition, offset by decreased volumes across certain assets.

NGL Gross Production — NGL production increased in 2010 compared to 2009, due primarily to increased NGL production at Discovery and increased volumes from our Piceance Basin expansion project.

Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009

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

•

$95.5 million increase attributable to increased commodity prices, which impact both sales and purchases;

•

$67.3 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $84.5 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $17.2 million due to generally higher average prices of commodities in 2010;

•

$6.9 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 in the first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a fire in East Texas and our Wyoming pipeline integrity and system enhancement project; and

•

$6.8 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition and changes in contract mix.

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

•

$67.3 million increase related to commodity derivative activities as discussed in the Operating Revenues section above;

•

$23.3 million increase as a result of higher commodity prices; and

•

$6.8 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition and changes in contract mix.

These increases were partially offset by:

•

$10.6 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 in the first quarter, 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 first quarter impact of a fire in East Texas and our Wyoming pipeline integrity and system enhancement project.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, repairs as a result of near record cold weather, and efficiency projects.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, increased in 2010 compared to 2009, primarily due to higher prices and increased NGL production, partially offset by increased plant fuel costs and higher costs and downtime related to turnarounds. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests include the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter and turnarounds at East Texas in 2010.

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 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 in the first quarter. 2009 results include the first quarter 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 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 in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

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 June 30,						Six Months Ended June 30,						Variance Three Months 2010 vs. 2009					Variance Six Months 2010 vs. 2009
	2010			2009			2010			2009			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of propane	$	61.8		$	46.8		$	242.8		$	179.6		$	15.0		32	%	$	63.2		35	%
Other		0.2			0.2			0.2			0.2			—		—	%		—		—	%
Gains (losses) from commodity derivative activity		0.2			(0.1	)		—			(0.1	)		0.3		*			0.1		100	%

Total operating revenues		62.2			46.9			243.0			179.7			15.3		33	%		63.3		35	%
Purchases of propane		63.1			41.1			230.2			148.1			22.0		54	%		82.1		55	%

Segment gross margin (a)		(0.9	)		5.8			12.8			31.6			(6.7	)	*			(18.8	)	(59	)%
Operating and maintenance expense		(2.6	)		(2.4	)		(5.2	)		(5.1	)		0.2		8	%		0.1		2	%
Depreciation and amortization expense		(0.3	)		(0.4	)		(0.6	)		(0.7	)		(0.1	)	(25	)%		(0.1	)	(14	)%
Other income — affiliates		3.0			—			3.0			—			3.0		100	%		3.0		100	%

Segment net income attributable to partners	$	(0.8	)	$	3.0		$	10.0		$	25.8		$	(3.8	)	*		$	(15.8	)	(61	)%

Other data:
Non-cash commodity derivative mark-to-market	$	—		$	(0.1	)	$	(0.6	)	$	0.1		$	0.1		100	%	$	(0.7	)	*
Propane sales volume (Bbls/d)		13,055			13,912			23,205			25,502			(857	)	(6	)%		(2,297	)	(9	)%

*	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 June 30, 2010 vs. Three Months Ended June 30, 2009

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

•

$17.9 million increase attributable to higher propane prices, which impact both sales and purchases; and

•

$0.3 million increase related to commodity derivative activity.

These increases were partially offset by:

•

$2.9 million decrease attributable to decreased propane sales volumes.

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.

Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Propane Sales Volume — Propane sales volumes decreased in 2010 compared to 2009. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect a late winter.

Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009

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

•

$77.1 million increase attributable to higher propane prices, which impact both sales and purchases; and

•

$0.1 million increase related to commodity derivative activity.

These increases were partially offset by:

•

$13.9 million decrease attributable to decreased propane sales volumes.

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. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect a late winter, 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.

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 June 30,						Six Months Ended June 30,						Variance Three Months 2010 vs. 2009					Variance Six Months 2010 vs. 2009
	2010 (a)			2009			2010 (a)			2009			Increase (Decrease)			Percent		Increase (Decrease)		Percent
	(Millions, except as indicated)
Operating revenues:
Sales of NGLs	$	1.0		$	0.4		$	2.8		$	1.0		$	0.6		150	%	$	1.8	180	%
Transportation, processing and other		2.6			1.4			5.6			2.6			1.2		86	%		3.0	115	%

Total operating revenues		3.6			1.8			8.4			3.6			1.8		100	%		4.8	133	%
Purchases of NGLs		1.1			0.5			2.5			1.0			0.6		120	%		1.5	150	%

Segment gross margin (b)		2.5			1.3			5.9			2.6			1.2		92	%		3.3	127	%
Operating and maintenance expense		(1.0	)		(0.2	)		(1.2	)		(0.5	)		0.8		400	%		0.7	140	%
Depreciation and amortization expense		(0.6	)		(0.4	)		(1.1	)		(0.8	)		0.2		50	%		0.3	38	%
Earnings from unconsolidated affiliates (c)		0.3			0.4			0.8			0.8			(0.1	)	(25	)%		—	—	%

Segment net income attributable to partners	$	1.2		$	1.1		$	4.4		$	2.1		$	0.1		9	%	$	2.3	110	%

Other data:
NGL pipelines throughput (Bbls/d) (c)		35,710			26,850			37,810			25,409			8,860		33	%		12,401	49	%

(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 June 30, 2010 vs. Three Months Ended June 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of increased throughput volumes from the Wattenberg pipeline acquisition and a market opportunity early in the year at Seabreeze, as well as higher per unit margins.

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

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result the Wattenberg pipeline acquisition and increased throughput volumes from a market opportunity early in the year at Seabreeze.

Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of a market opportunity early in the year at Seabreeze and the Wattenberg pipeline acquisition, as well as higher per unit margins. 2009 results include the first quarter 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.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result of increased volumes from a market opportunity early in the year at Seabreeze and the Wattenberg pipeline acquisition. 2009 results include the first quarter 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;

•

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 In July 2010, we acquired Atlantic Energy for $49.0 million plus propane inventory and other working capital of $17.3 million and acquired an additional 55% interest in Black Lake for $16.5 million, financed with borrowings under our revolving credit facility.

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 an $850.0 million revolving credit facility that matures June 21, 2012, or the Credit Agreement. Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank’s commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.

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 August 5, 2010, we had approximately $151.6 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 August 5, 2010, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $98.0 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 $55.0 million of these guarantees. As of August 5, 2010 we converted our existing $10.0 million outstanding letter of credit to a contingent issuance letter of credit facility, for which we pay a fee of 0.50% per annum. We will pay a net fee of 1.75% per annum on letters of credit issued on this facility. These parental guarantees and contingent issuance letter of credit facility reduce the amount of cash we may be required to post as collateral. This contingent issuance letter of credit facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility. As of August 5, 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.

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 June 30, 2010, we had $4.8 million in cash and cash equivalents. Of this balance, as of June 30, 2010, $4.3 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. Congress recently passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has the potential to impact our cash collateral requirements for our trading activities and derivative positions depending on the final regulations adopted by the United States Commodity Futures Trading Commission and the SEC.

We had a working capital deficit of $6.1 million and working capital of $6.6 million as of June 30, 2010 and December 31, 2009, respectively. Excluding net derivative working capital liabilities of $27.5 million and $34.2 million, working capital would be $21.4 million and $40.8 million as of June 30, 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:


	Six Months Ended June 30,
	2010			2009
	(Millions)
Net cash provided by operating activities	$	88.7		$	51.3
Net cash used in investing activities	$	(36.3	)	$	(99.0	)
Net cash used in financing activities	$	(49.7	)	$	(9.6	)

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 $2.0 million for the six months ended June 30, 2010, which is net of cash receipts of $1.8 million associated with rebalancing our portfolio, and received cash for settlement of our commodity derivative instruments for the six months ended June 30, 2009 of $14.4 million approximately $3.9 million of which was associated with rebalancing our portfolio. In addition we received $2.2 million from DCP Midstream, LLC, related to the sale of surplus equipment as of June 30, 2010, which we have treated as an operating cash flow, due to the title to the equipment not transferring to DCP Midstream, LLC as of the balance sheet date.

We received cash distributions from unconsolidated affiliates of $20.0 million and $3.0 million during the six months ended June 30, 2010 and 2009, respectively. Distributions exceeded earnings by $5.5 million and $0.4 million for the six months ended June 30, 2010 and 2009, respectively.

Net Cash Used in Investing Activities — Net cash used in investing activities during the six months ended June 30, 2010 was comprised of: (1) acquisition expenditure of $22.0 million related to our acquisition of the Wattenberg NGL pipeline; (2) capital expenditures of $25.4 million (our portion of which was $15.7 million and the noncontrolling interest holders’ portion was $9.7 million); and (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 $1.7 million.

Net cash used in investing activities during the six months ended June 30, 2009 was comprised of: (1) capital expenditures of $118.4 million (our portion of which was $51.4 million and the noncontrolling interest holders’ portion was $67.0 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) investments in Discovery of $5.8 million; and (3) a net payment of $0.1 million related to our acquisition of Michigan Pipeline & Processing, LLC; partially offset by (4) net proceeds from sale of available-for-sale securities of $25.0 million; and (5) proceeds from sale of assets of $0.3 million.

Net Cash Used in Financing Activities — Net cash used in financing activities during the six months ended June 30, 2010 was comprised of: (1) distributions to our unitholders and general partner of $49.1 million; (2) distributions to noncontrolling interests of $8.2 million; and (3) purchase of additional interest in a subsidiary of $3.5 million; partially offset by (4) contributions from noncontrolling interests of $9.1 million; and (5) net borrowings of $2.0 million.

Net cash used in financing activities during the six months ended June 30, 2009 was comprised of: (1) distributions to our unitholders and general partner of $40.2 million; (2) net repayments of debt of $18.5 million; and (3) distributions to noncontrolling interests of $4.9 million; partially offset by (4) contributions from noncontrolling interests of $50.3 million; (5) net changes in advances to predecessor from DCP Midstream, LLC of $3.0 million; and (6) contributions from DCP Midstream, LLC of $0.7 million.

During the six months ended June 30, 2010, total outstanding indebtedness under our $850.0 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 $598.3 million and did not exceed $647.2 million. The weighted average indebtedness outstanding for the six months ended June 30, 2010 was $624.2 million.

We had liquidity, which is available commitments under the Credit Agreement, of $234.6 million as of June 30, 2010.

During the six months ended June 30, 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 six months ended June 30, 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 six months ended June 30, 2009, we had the following net movements on our revolving credit facility:

•

$25.0 million borrowings to fund repayment of our term loan facility; partially offset by

•

$18.5 million net repayments.

During the six months ended June 30, 2009, we had a repayment of $25.0 million on our term loan facility and released $25.0 million of restricted investments which were required as collateral for the 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 , including certain system integrity and safety improvements, 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 expenditures for expansion capital improvements of between $30 million and $35 million for the year ending December 31, 2010. The board of directors may approve additional growth capital during the year, at their discretion.

Our expansion capital improvements forecast of between $30 million and $35 million for the year ended December 31, 2010, includes $18 million of expenditures for capital improvement related to our January 2010 Wattenberg pipeline acquisition, of which we have invested $2.0 million as of June 30, 2010.

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


	Six Months Ended June 30, 2010						Six Months Ended June 30, 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	$	3.9	$	11.8	$	15.7	$	8.9	$	42.5	$	51.4
Noncontrolling interest portion		4.2		5.5		9.7		18.2		48.8		67.0

Total	$	8.1	$	17.3	$	25.4	$	27.1	$	91.3	$	118.4

In addition, we invested cash in unconsolidated affiliates of $0.7 million and $5.8 million during the six months ended June 30, 2010 and 2009, respectively, of which $0.7 million and $1.6 million, respectively, was to fund our share of capital expansion projects, and $4.2 million in 2009 was to fund repairs to Discovery following damage caused by Hurricane Ike in 2008.

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 $49.1 million during the six months ended June 30, 2010, as compared to $40.2 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.

Description of the Credit Agreement — The Credit Agreement consists of an $850.0 million revolving credit facility at June 30, 2010. The Credit Agreement matures on June 21, 2012. As of June 30, 2010, the outstanding balance on the revolving credit facility was $615.0 million. The term loan was repaid during the first quarter of 2010.

Our obligations under the revolving credit facility are unsecured. The term loan facility, which was repaid during the first quarter of 2010, was secured at all times by high-grade securities, which we 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 June 30, 2010 and December 31, 2009, we had a $0.4 million and a $0.3 million, respectively, outstanding letter of credit issued under the Credit Agreement.

As of June 30, 2010, the weighted-average interest rate on our revolving credit facility was 0.92% per annum.

Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of June 30, 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)	$	665.7	$	25.7	$	640.0	$	—	$	—
Operating lease obligations (b)		46.9		14.4		22.5		8.9		1.1
Purchase obligations (c)		533.5		243.2		169.8		61.2		59.3
Other long-term liabilities (d)		9.5		—		0.4		0.1		9.0

Total	$	1,255.6	$	283.3	$	832.7	$	70.2	$	69.4

(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 $5.6 million of purchase orders for capital expenditures and $527.9 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 June 30, 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 $9.0 million of asset retirement obligations and $0.5 million of environmental reserves recognized in the June 30, 2010 condensed consolidated balance sheet.

Recent Accounting Pronouncements

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.

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.

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 June 30, 2010, the effective weighted-average interest rate on our $615.0 million of outstanding revolver debt was 4.34%, 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 June 30, 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.

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 August 5, 2010:


Period	Commodity	Notional Volume	Reference Price	Swap Price Range
July 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 2014	Natural Gas	1,000 MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$5.06/MMBtu
July 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
July 2010 — December 2010	Natural Gas	1,000 MMBtu/d	NYMEX Final Settlement Price (c)	$8.22/MMBtu
January 2011 — December 2013	Natural Gas	800 MMBtu/d	NYMEX Final Settlement Price (c)	$8.22/MMBtu
July 2010 — December 2010	Natural Gas Basis	1,000 MMBtu/d	IFERC Monthly Index Price for Panhandle Eastern Pipe Line (d)	NYMEX less $0.68/MMBtu
January 2011 — December 2013	Natural Gas Basis	800 MMBtu/d	IFERC Monthly Index Price for Panhandle Eastern Pipe Line (d)	NYMEX less $0.68/MMBtu
July 2010 — December 2010	Crude Oil	2,415 Bbls/d	Asian-pricing of NYMEX crude oil futures (e)	$63.05 - $87.25/Bbl
July 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.

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	$	4.9
Crude oil prices	$	5.00	Barrel	$	20.1
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.

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 June 30, 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

Except for the matter noted below, 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.

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation arose from a commercial dispute involving the construction of our Wilbreeze pipeline in 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. In June 2010 we settled this matter with Driver for $0.3 million.

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.

The following are new or modified risk factors that should be read in conjunction with the risk factors disclosed in our 2009 Form 10-K:

Recent spills and their aftermath could lead to additional governmental regulation of the offshore exploration and production industry, which may result in substantial cost increases or delays in our offshore natural gas gathering activities.

In April 2010, a deepwater exploration well located in the Gulf of Mexico, owned and operated by companies unrelated to us, sustained a blowout and subsequent explosion leading to the leaking of hydrocarbons. In response to this event, certain federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. A federal moratorium on deepwater drilling has been implemented and is currently set to expire on November 30, 2010, but the Bureau of Ocean Energy Management may elect to shorten or extend the duration of the moratorium. Our deepwater Gulf of Mexico operations include only our 40% interest in Discovery. This spill and its aftermath could lead to additional governmental regulation of the offshore exploration and production industry, which may result in substantial cost increases or delays in our offshore natural gas gathering activities, which could materially impact our business, financial condition and results of operations. We cannot predict with any certainty what form any additional regulation or limitations would take.

Recent federal legislation could affect our ability to use derivative instruments to reduce the effect of commodity price and interest rate risks associated with our business.

We hedge both our commodity risk and our interest rate risk. The recently adopted comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives and swaps markets and entities that participate in those markets. Regulations stemming from this new legislation may impose new requirements related to trade-execution and reporting of over-the-counter derivatives and swaps. The new legislation and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Any of these consequences could have a material adverse effect on us, our financial condition, and results of operations.

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).

10.1	*	Propane Sales Contract, effective May 1, 2008, between Spectra Energy Propane LLC and Gas Supply Resources LLC.

10.2		Amendment to Propane Sales Contract, between Spectra Energy Propane LLC and Gas Supply Resources LLC.

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.

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 August 9, 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)

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).

10.1	*	Propane Sales Contract, effective May 1, 2008, between Spectra Energy Propane LLC and Gas Supply Resources LLC.

10.2		Amendment to Propane Sales Contract, between Spectra Energy Propane LLC and Gas Supply Resources LLC.

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.