~~Issuance of Unregistered Units~~

In February 2008, we satisfied the financial tests contained in our partnership agreement for the early conversion of 50% of the outstanding subordinated units held by DCP Midstream, LLC into common units on a one-for-one basis. Before the conversion, DCP Midstream, LLC held 7,142,857 subordinated units, and after the conversion, DCP Midstream, LLC held 3,571,429 subordinated units. On February 17, 2009, we satisfied the financial tests contained in our partnership agreement for the early conversion of the remaining 3,571,429 outstanding subordinated units held by DCP Midstream, LLC into common units on a one for one basis.

Distributions of Available Cash

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

~~In January 2008, our registration statement on~~

~~Form S-3~~ to register the 3,005,780 common limited partner units represented in the June 2007 private placement agreement and the 2,380,952 common limited partner units represented in the August 2007 private placement agreement was declared effective by the SEC.

~~In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.1 million, net of offering costs.~~

Definition of Available Cash— Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

less the amount of cash reserves established by our general partner to:

provide for the proper conduct of our business;


	•	~~less the amount of cash reserves established by our general partner to:~~

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


	•	~~provide for the proper conduct of our business;~~

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

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

provide funds for distributions to our 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.~~

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.

Minimum Quarterly Distribution— The Minimum Quarterly Distribution, as set forth in the partnership agreement, is $0.35 per unit per quarter, or $1.40 per unit per year. Our current quarterly distribution is ~~$0.60~~$0.6175 per unit, or ~~$2.40~~$2.47 per unit annualized. There is no guarantee that we will maintain our current distribution or pay the Minimum Quarterly Distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. ~~We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our credit agreement.~~ Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement” for a discussion of the restrictions included in our credit agreement that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights— ~~Prior to June 2007, our~~As of December 31, 2010 the general partner ~~was~~is entitled to 2%a percentage of all quarterly distributions ~~since inception that we made. Our~~equal to its general partner interest of

approximately 1% and limited partner interest of 1%. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general ~~partner has not participated in certain issuances of common units. Therefore, the general partner’s 2% interest has been diluted to approximately 1% as of December 31, 2008. The general~~ partner’s interest may be ~~further~~ reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by our general partner entitle it to receive an increasing share of Available Cash as pre-defined distribution targets have been achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. Our general partner’s incentive distribution rights were not reduced as a result of our ~~March 2008~~recent common ~~limited partner~~ unit ~~offering,~~offerings, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read theDistributions of Available Cash ~~during the Subordination Periodand~~~~Distributions of Available Cash~~ after the Subordination Periodsections in Note 1213 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

On January 27, ~~2009,~~2011, the board of directors of DCP Midstream GP, LLC declared a quarterly distribution of ~~$0.60~~$0.6175 per unit, which was paid on February ~~13, 2009,~~14, 2011, to unitholders of record on February ~~6, 2009.~~

7, 2011.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” contained herein.


Item 6.	*Selected Financial Data*

The following table shows our selected financial data for the periods and as of the dates indicated, which is derived from the consolidated financial statements. These consolidated financial statements include our accounts, and prior to December 7, 2005, the assets, liabilities and operations contributed to us by DCP Midstream, LLC and its wholly-owned subsidiaries, or DCP Midstream Partners Predecessor, upon the closing of our initial public offering, which have been combined with the historical assets, liabilities and operations of our wholesale propane logistics business which we acquired from DCP Midstream, LLC in November 2006, ~~and~~ our initial 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, our 40% limited liability company interest in Discovery Producer Services, LLC, or Discovery, and a non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, which we acquired from DCP Midstream, LLC in July ~~2007. These were transactions~~2007 and our additional 25.1% limited liability interest in East Texas, which we acquired from DCP Midstream, LLC in April 2009. 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 was accounted for under the equity method of accounting. Subsequent to our acquisition of an additional 25.1% limited liability company interest in April 2009, we own a 50.1% limited liability company interest in East Texas and account for East Texas as a consolidated subsidiary. This transaction was among entities under common control; accordingly, our financial information includes the historical results of ~~our wholesale propane logistics business, Discovery~~entities and ~~East Texas~~interests contributed to us by DCP Midstream, LLC for all periods presented. The information contained herein should be read together with, and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in thisForm 10-K.

Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not be indicative of our future financial conditions or results of operations. A discussion on our critical accounting estimates is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations:~~Operations.”

Year Ended December 31,
2008(a) 2007(a) 2006 2005 2004
(Millions, except per unit data)

Statements of Operations Data:

Total operating revenues(b) $ 1,285.8 $ 873.3 $ 795.8 $ 1,144.3 $ 834.0

Operating costs and expenses:
Purchases of natural gas, propane and NGLs 1,061.2 826.7 700.4 1,047.3 760.6
Operating and maintenance expense 43.0 32.1 23.7 22.4 19.8
Depreciation and amortization expense 36.5 24.4 12.8 12.7 14.7
General and administrative expense 24.0 24.1 21.0 14.2 8.7
Other (1.5 ) — — — —

Total operating costs and expenses 1,163.2 907.3 757.9 1,096.6 803.8

Operating income (loss) 122.6 (34.0 ) 37.9 47.7 30.2
Interest income 5.6 5.3 6.3 0.5 —
Interest expense (32.8 ) (25.8 ) (11.5 ) (0.8 ) —
Earnings from equity method investments(c) 34.3 39.3 29.2 25.7 17.6
Impairment of equity method investment(d) — — — — (4.4 )
Non-controlling interest in income (3.9 ) (0.5 ) — — —
Income tax expense(e) (0.1 ) (0.1 ) — (3.3 ) (2.5 )

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9 $ 69.8 $ 40.9
Less:
Net income attributable to predecessor operations(f) — (3.6 ) (26.6 ) (65.1 ) (40.9 )
General partner interest in net income (11.9 ) (2.2 ) (0.7 ) (0.1 ) —

Net income (loss) allocable to limited partners $ 113.8 $ (21.6 ) $ 34.6 $ 4.6 $ —

Net income (loss) per limited partner unit-basic and diluted $ 3.25 $ (1.05 ) $ 1.90 $ 0.20 $ —


	Year Ended December 31,
	2010(a)			2009(a)			2008(a)			2007(a)			2006
	(Millions, except per unit amounts)
Statements of Operations Data:
Sales of natural gas, propane, NGLs and condensate	$	1,162.7		$	913.0		$	1,672.7		$	1,376.5		$	1,232.2
Transportation, processing and other		115.3			95.2			86.1			57.4			50.0
(Losses) gains from commodity derivative activity, net(b)		(8.5	)		(65.8	)		71.7			(87.7	)		(1.0	)

Total operating revenues(c)		1,269.5			942.4			1,830.5			1,346.2			1,281.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,032.6			776.2			1,481.0			1,185.6			1,085.7
Operating and maintenance expense		79.8			69.7			77.4			59.3			48.1
Depreciation and amortization expense		73.7			64.9			53.2			40.2			27.4
General and administrative expense		33.7			32.3			33.3			36.2			32.5
Step acquisition — equity interest re-measurement gain		(9.1	)		—			—			—			—
Other income		(1.0	)		—			(1.5	)		—			—
Other income — affiliates		(3.0	)		—			—			—			—

Total operating costs and expenses		1,206.7			943.1			1,643.4			1,321.3			1,193.7

Operating income (loss)		62.8			(0.7	)		187.1			24.9			87.5
Interest income		—			0.3			6.1			5.6			6.3
Interest expense		(29.1	)		(28.3	)		(32.8	)		(25.7	)		(11.5	)
Earnings from unconsolidated affiliates(d)		23.8			18.5			18.2			24.7			17.2

Income (loss) before income taxes		57.5			(10.2	)		178.6			29.5			99.5
Income tax expense		(0.3	)		(0.6	)		(0.6	)		(0.8	)		(1.8	)

Net income (loss)		57.2			(10.8	)		178.0			28.7			97.7
Net income attributable to noncontrolling interests		(9.2	)		(8.3	)		(36.1	)		(29.8	)		(23.9	)

Net income (loss) attributable to partners	$	48.0		$	(19.1	)	$	141.9		$	(1.1	)	$	73.8
Less:
Net loss (income) attributable to predecessor operations (e)		—			1.0			(16.2	)		(18.3	)		(38.5	)
General partner interest in net income or net loss		(16.9	)		(12.7	)		(13.0	)		(3.9	)		(0.6	)

Net income (loss) allocable to limited partners	$	31.1		$	(30.8	)	$	112.7		$	(23.3	)	$	34.7

Net income (loss) per limited partner unit-basic and diluted	$	0.86		$	(0.99	)	$	4.11		$	(1.14	)	$	1.98

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	1,169.1		$	1,000.1		$	882.7		$	737.2		$	423.0
Total assets	$	1,700.6		$	1,481.5		$	1,419.7		$	1,380.8		$	874.4
Accounts payable	$	136.7		$	128.6		$	107.6		$	223.8		$	164.9
Long-term debt	$	647.8		$	613.0		$	656.5		$	630.0		$	268.0
Partners’ equity	$	518.1		$	377.7		$	395.1		$	232.4		$	318.8
Noncontrolling interests	$	220.1		$	227.7		$	167.7		$	155.1		$	101.7
Total equity	$	738.2		$	605.4		$	562.8		$	387.5		$	420.5

Other Information:
Cash distributions declared per unit	$	2.438		$	2.400		$	2.390		$	2.115		$	1.565
Cash distributions paid per unit	$	2.420		$	2.400		$	2.360		$	1.975		$	1.230

Year Ended December 31,
2008(a) 2007(a) 2006 2005 2004
(Millions, except per unit data)

Balance Sheet Data (at period end):

Property, plant and equipment, net $ 629.3 $ 500.7 $ 194.7 $ 178.7 $ 179.3
Total assets $ 1,180.0 $ 1,120.7 $ 665.9 $ 680.1 $ 472.5
Accounts payable $ 78.4 $ 165.8 $ 117.3 $ 138.3 $ 63.5
Long-term debt $ 656.5 $ 630.0 $ 268.0 $ 210.1 $ —
Partners’ equity $ 329.1 $ 168.4 $ 267.7 $ 320.7 $ 400.5
Other Information:

Cash distributions declared per unit $ 2.390 $ 2.115 $ 1.565 $ 0.095 N/A
Cash distributions paid per unit $ 2.360 $ 1.975 $ 1.230 N/A N/A


(a)		Includes the effect of the ~~acquisition~~following acquisitions prospectively from their respective dates of ~~the~~acquisition; (1) our Southern Oklahoma system acquired in May ~~2007,~~2007; (2) certain subsidiaries of Momentum Energy Group, Inc. acquired in August ~~2007 and~~2007; (3) Michigan Pipeline & Processing, LLC acquired in October ~~2008.~~2008; (4) certain companies acquired from MichCon Pipeline Company in November 2009; (5) the Wattenberg pipeline acquired from Buckeye Partners, L.P. in January 2010; (6) an additional 5% interest in Collbran Valley Gas Gathering LLC, acquired from Delta Petroleum Company in February 2010; (7) an additional 50% interest in Black Lake Pipeline Company, or Black Lake, acquired from an affiliate of BP PLC in July 2010; and (8) the acquisition of Atlantic Energy from UGI Corporation in July 2010.

Prior

to our acquisition of an additional 50% interest in Black Lake, in July 2010, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

(b)		Includes the effect of the ~~acquisition of~~NGL Hedge acquired from DCP Midstream, LLC in April 2009 and the Swap entered into by DCP Midstream, LLC in March 2007 and contributed to us in July 2007. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component which commenced in April 2009 and expired in March 2010. The Swap was for a total of ~~approximately~~ 1.9 million barrels at $66.72 per barrel.

(c)

We hedge the proportionate ownership of East Texas. Results shown include the unhedged portion of East Texas owned by DCP Midstream, LLC. 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.

(d)	Includes the effect of the acquisition of a ~~25% limited liability company interest in East Texas and a~~ 40% limited liability company interest in Discovery from DCP Midstream, LLC for all periods presented, as well as our proportionate share of the earnings of Black Lake ~~East Texas and Discovery.~~through July 2010. Earnings for Discovery and Black Lake include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the investments.

~~(d)~~		~~In 2004, we recorded our proportionate share of an impairment charge on Black Lake totaling $4.4 million.~~

(e)		Income tax expense for 2004 through 2005 is applicable to the results of operations of our wholesale propane logistics business. We incurred no income tax expense in 2006, due to the change in tax status of our wholesale propane logistics business in December 2005. Income tax expense in 2008 and 2007 represents a margin-based franchise tax in Texas, or the Texas margin tax and a Michigan business tax. See Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

~~(f)~~		Includes ~~the net income attributable to DCP Midstream Partners Predecessor through December 7, 2005,~~ the net income (loss) attributable to our wholesale propane logistics business prior to the date of our acquisition from DCP Midstream, LLC in November 2006, ~~and~~ the net income attributable to the acquisition of aan initial 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery, and the Swap prior to the date of our acquisition from DCP Midstream, LLC in July ~~2007.~~2007, and the net income attributable to the acquisition of an additional 25.1% limited liability company interest in East Texas prior to the date of our acquisition from DCP Midstream, LLC in April 2009.

Item 7. 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 consolidated financial statements and notes included elsewhere in this annual report. We refer to the assets, liabilities and operations contributed to us by DCP Midstream, LLC and its wholly-owned subsidiaries upon the closing of our initial public offering as DCP Midstream Partners Predecessor, which have been combined with the historical assets, liabilities and operations of our wholesale propane logistics business, which we acquired from DCP Midstream, LLC in November 2006, and our 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, our 40% limited liability company interest in Discovery Producer Services, LLC, or Discovery, and a non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, which we acquired from DCP Midstream, LLC in July 2007. We refer to DCP Midstream Partners Predecessor, our wholesale propane logistics business, East Texas and Discovery

~~collectively as our “predecessors.” The financial information contained herein includes, for each period presented, our accounts, and those of our predecessors.~~

Overview

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


	•	our Natural Gas Services segment, which consists of (1) our Northern Louisiana natural gas gathering, processing and transportation system; (2) our Southern Oklahoma system acquired in May 2007; (3) our limited liability company interest in East Texas, our limited liability company interest in Discovery, and the Swap, acquired in July 2007 from DCP Midstream, LLC; (4) our Colorado and Wyoming systems, acquired in August 2007 from DCP Midstream, LLC, which were acquired by DCP Midstream, LLC from Momentum Energy Group, Inc., or MEG, in August 2007 (referred to as the MEG acquisition); and (5) our Michigan systems, acquired in October 2008 from Michigan Pipeline & Processing, LLC (referred to as the MPP acquisition);

	•	our Wholesale Propane Logistics segment, which consists of six owned rail terminals, one of which was idled in 2007 to consolidate our operations, one leased marine terminal, one pipeline terminal which became operational in May 2007, and access to several open access pipeline terminals; and

	•	~~our NGL Logistics segment, which consists of our Seabreeze and Wilbreeze NGL transportation pipelines, and a non-operated equity interest in the Black Lake interstate NGL pipeline.~~

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 ~~(1) DCP Midstream Partners Predecessor for periods prior to December 7, 2005, (2)~~ our ~~wholesale propane logistics business that we acquired in November 2006 and (3) our 25%~~additional 25.1% limited liability company interest in East Texas ~~40% interest in Discovery, and the Swap that we~~ acquired ~~in July 2007,~~ from DCP Midstream, LLC in ~~transactions~~April 2009, a transaction among entities under common ~~control.~~ control, which we refer to 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 ~~predecessors~~predecessor for all periods presented. ~~The historical financial statements~~

Crude oil and NGL prices have generally remained at favorable levels, although natural gas prices continue to decline and remain lower than prices in 2008 and 2009. With the exception of ~~DCP Midstream Partners Predecessor included~~certain higher liquids content and emerging gas shale regions where drilling activity remains high, the lower natural gas prices are resulting in ~~this annual report~~significantly 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 ~~discussed elsewhere herein include DCP Midstream Partners Predecessor’s 50%~~NGL prices.

During January and February, we experienced near record cold weather, causing operating challenges at our East Texas and Northern Louisiana plants, creating periods of low NGL recoveries and volume curtailments due to plant shut downs and producer wellhead freeze offs.

From May to November, we had an extended planned outage related to an inspection at our Providence wholesale propane terminal, with lower unit margins resulting from the associated logistics of shifting inventory and sales volumes to our other terminals. Earlier in the year, 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 several aspects of 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 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 ~~Pipe Line Company, or Black Lake. However, effective December 7, 2005, DCP Midstream, LLC retained~~to 100%. In July, we also closed on an acquisition which expanded our existing northeastern U.S. wholesale propane logistics business into the mid-Atlantic region through the addition of a ~~5% interest~~marine import terminal and ~~we own a 45% interest in Black Lake.~~

~~Recent Events~~

~~On February 27, 2009, a jury~~storage facility in the ~~District Count, Harris County, Texas rendered a verdict in favor~~Port of ~~El Paso E&P Company, L.P. and against one of~~Chesapeake, Virginia. Prior to year-end, we further expanded our subsidiaries and DCP Midstream. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which includes periods of time prior to our ownership of this asset. Our responsibility for this judgment will be limited to the time period after we acquired the asset from DCP Midstream in December 2005. We intend to appeal this decision and will continue to defend ourselves vigorously against this claim. Nevertheless, as a result of the jury verdict we have reserved in accordance with accounting principles generally acceptedNGL logistics business in the ~~United States~~Midwest, Sarnia and Northeast supply markets through the acquisition of ~~America, or GAAP, a contingent liability of $2.5 million for this matter, which is included~~an NGL storage facility in our consolidated financial statements for the year ended December 31, 2008. This reserve changes our financial results as reported in our earnings release dated February 25, 2009, which date preceded the jury verdict.

Marysville, Michigan.

On ~~February 25, 2009,~~November 4, 2010, we entered into ~~a Contribution Agreement~~agreements with DCP Midstream, LLC, ~~whereby DCP Midstream, LLC will contribute an additional 25.1%~~to acquire a 33.33% interest in ~~East~~Southeast Texas, ~~to us in exchange~~ for ~~3.5 million Class D units, providing us with~~$150.0 million. The Southeast Texas system is a ~~50.1% interest in East Texas following the expected closing~~fully integrated midstream business which includes 675 miles of the transaction in April 2009. This closing date is subject to extension for up to 45 days to allow for repairs or replacement to our reasonable satisfaction any assets destroyed or damaged by certain casualty losses and time to enable the plant to process all available inlet volumes as defined in the Contribution Agreement. The Class D units will automatically convert into common units in August 2009 and will not be eligible to receive

a distribution until the second quarter distribution payable in August 2009. DCP Midstream, LLC has agreed to provide a fixed-price NGL derivative by NGL component for the period of April 2009 to March 2010 for the acquired interest. Subsequent to this transaction, we will consolidate East Texas in our consolidated financial statements.

~~On February 11, 2009, we announced, along with DCP Midstream, LLC, that our East Texas~~natural gas pipelines, three natural gas processing ~~complex~~plants with recently increased processing capacity totaling 380 MMcf/d and ~~residue~~ natural gas ~~delivery system known as~~storage assets with 9 Bcf of existing storage capacity. The terms of the ~~Carthage Hub, have been temporarily shut~~joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage

capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in ~~following~~Southeast Texas. The transaction closed on January 1, 2011.

Through the growth opportunities executed, we increased our business diversity, geographic and resource exposure, and our fee-based margins. Our integration efforts related to the acquisitions are progressing according to plan. The Wattenberg capital expansion project, which we expect to complete in early 2011, is also progressing on plan.

We believe our financial positioning is a ~~fire that was caused by a third party underground pipeline outside~~key element of our ~~property~~growth strategy and that our accomplishments related to our financial objectives position us well in terms of both liquidity and cost of capital to support our growth plans. In September, we successfully executed our inaugural public debt offering through the issuance of $250.0 million of senior notes due 2015. We raised $189.3 million in capital through the successful execution of two public equity offerings in August and November.

Financial results for the year were in line ~~that ruptured. No employees or contractors were injured~~with our previously provided 2010 forecast. Resuming distribution growth was an important 2010 objective, with the past year serving as a transition year to consistent distribution growth. We raised our distribution in the incident. There was no significant damage to the natural gas processing complex. As of February 25, 2009, the complex began processing through one of the five plants, and it is expected that full processing capacities will be restored for the entire complex over the next 30 days. Residue gas will be redelivered into limited available pipeline interconnects while the Carthage Hub undergoes inspection and repairs.

On February 17, 2009, the remaining 3,571,429 DCP Partners subordinated units were converted to common units following the completion of the subordination period and satisfactory completion of all subordination period tests contained in the DCP Partners’ partnership agreement.

In February 2009, we entered into interest rate swap agreements to convert $275.0 million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to interest rate fluctuations. These interest rate swaps commence in December 2010 and expire in June 2012. In November 2008, we entered into interest rate swap agreements to convert $150.0 million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to interest rate fluctuations. These interest rate swaps expire in December 2010.

As a result of hurricanes during the third quarter of 2008, certain of our owned and operated facilities were fully or partially curtailed pending resumption of electric power and operations at downstream third party NGL facilities, in some cases. All of our operated assets have since been returned to service. There has been some temporary impact to demand as third party NGL facilities are returned to service. The net income impact of hurricane-related damages and lost margins due to curtailed operations for the thirdsecond and fourth quarters, resulting in a 3% increase in our quarterly distribution rate over the rate paid in the fourth quarter of ~~2008 was approximately $14.7 million, including losses~~2009. The distributions reflect our business results as well as our recent execution on growth opportunities.

General Trends and Outlook

In 2011, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our ~~equity method investment~~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 approximately 60% of our estimated margins, and our highly hedged commodity position, the objective of which is to protect against downside risk in ~~Discovery.~~

~~In January 2009, repairs were completed on Discovery’s30-inch~~ ~~mainline, restoring approximately 85% of volumes~~our distributable cash flows.

We incur capital expenditures for our consolidated entities and ~~margins to the system. With the completion of the18-inch~~ ~~lateral repairs, the remaining volumes are expected to be restored in early March. We did not receive a fourth quarter distribution from Discovery, which would have been paid during January 2009.~~our unconsolidated affiliates. We anticipate ~~distributions to resume~~maintenance capital expenditures of between $10.0 and $15.0 million, and expenditures for expansion capital of between $35.0 and $50.0 million in 2011 including $10.0 million for the ~~first quarter of 2009, which will be paid in April 2009. Discovery’s offshore gathering system had been damaged by hurricane Ike in September 2008 when an18-inch~~ ~~lateral was severed from its connection~~expansion to ~~the30-inch~~ ~~mainline in 250 feet of water.~~

~~On January 27, 2009, the~~storage capacity at our Southeast Texas system. The board of directors may approve additional growth capital during the year at their discretion. This capital does not include any acquisitions or additional investment opportunities that may be identified throughout the course of the ~~general partner declared a quarterly distribution of $0.60 per unit, payable on February 13, 2009 to unitholders of record on February 6, 2009.~~

In January 2009, Don Baldridge was appointed to Vice President, Business Development. Previously, Mr. Baldridge was Vice President, Corporate Development for DCP Midstream, LLC. Mr. Baldridge is replacing Greg K. Smith, who was appointed Vice President, Gas Supply for DCP Midstream, LLC.

~~In early January 2009, the second phase of~~year and approved by our ~~Wyoming pipeline~~management and ~~systems enhancement project was completed, returning over 80% of the system volumes to service. The final phase is on target for completion in March.~~

In December 2008, we made contributions of $1.9 million to Discovery, $1.6 million of which was to fund hurricane damages and $0.3 million was to fund capital expansion. In December 2008 we received a distribution of $2.5 million from East Texas and paid a contribution of $2.6 million to East Texas to fund capital expansion.

~~In October 2008, due to executive management rotational changes at ConocoPhillips, Willie C.W. Chiang and Sigmund L. Cornelius resigned as directors of the board of directors of~~ our ~~general partner, and John E.~~

~~Lowe and Gregory J. Goff were appointed as the ConocoPhillips representatives to the~~ board of directors. ~~Mr. Lowe~~

In 2011, we expect to continue to pursue a multi-faceted growth strategy, which may include 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 continue to 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 ~~serves as assistant~~available to us. To the ~~Chief Executive Officer~~extent our underlying assumptions about or interpretations of ~~ConocoPhillips, an affiliate of~~available information prove to be incorrect, our ~~general partner~~actual results may vary materially from our expected results.

Natural Gas Gathering and ~~Mr. Goff currently serves as Senior Vice President, Commercial of ConocoPhillips. Mr. Goff was also appointed to DCP Partners’ compensation committee in December 2008.~~

~~In October 2008, we acquired Michigan Pipeline &~~ Processing ~~LLC, or MPP, a privately held company engaged in~~Margins— Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and ~~treating services~~processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, ~~produced from~~NGLs and condensate. Commodity prices, which are impacted by the ~~Antrim Shale of northern Michigan~~balance between supply and demand, have historically been volatile. Throughput volumes could decline should natural gas ~~transportation within Michigan. Under~~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 ~~terms~~United States. During 2010, petrochemical demand remained strong for NGLs as NGLs were a lower cost feedstock when compared to crude oil derived feedstocks. We anticipate this continuing in 2011.

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 acquisition, we paid a purchase price of $145.0 million, plus net working capital and other adjustments of $3.4 million, subject to additional customary purchase price adjustments, plus up to an additional $15.0 million towinter months when their retail customers consume the sellers depending on the earnings of the assets after a three-year period. We financed the acquisition through utilization of our credit facility. In addition, we entered into a separate agreement that provides the seller with available treating capacity on certain Michigan assets. The seller agreed to pay us up to $1.5 million annuallymost propane for up to nine years if they do not meet certain criteria, including providing additional volumes for treatment. These payments would reduce goodwill as a return of purchase price. This agreement may be terminated earlier if certain performance criteria of Michigan assets are satisfied. Certain of these performance criteria were satisfied, and as a result, the amount has been reduced to $0.8 million per year as of February 23, 2009. We initially held a $25.0 million letter of credit to secure the seller’s performance under this agreement and to secure the seller’s indemnification obligation under the acquisition agreement; however as a result of the satisfaction of certain performance conditions, this amount has been reduced to $22.5 million as of February 23, 2009. The fees under the omnibus agreement with DCP Midstream, LLC increased $0.4 million per year effective October 1, 2008, in connection with the acquisition.

home heating.

Factors That May Significantly Affect Our Results

~~Capital Markets~~

Beginning in the third quarter of 2008, the capital markets experienced volatility, uncertainty and interventions by various governments around the globe. The effects of these market conditions include significant changes in the valuation of equity securities and overnight and longer-term borrowing rates. The availability of credit through traditional sources of funding such as the commercial paper, bank lending and the private and public placement debt markets also decreased dramatically. The uncertainty in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to finance their drilling programs and limiting our ability to grow our operations through acquisitions or organic growth projects. These events may impact our counterparties’ ability to perform under their credit or commercial obligations. While we did not experience significant collection issues during 2008, we continue to monitor the payment patterns of our customers. Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines. To date, our counterparties to our existing derivative instruments have fully performed under their commitments. Due to the bankruptcy of Lehman Brothers Commercial Bank, or Lehman Brothers, a lender to our Credit Agreement, the availability of borrowings under this facility has been reduced by approximately $25.4 million. Accordingly, the capacity under our Credit Agreement is approximately $824.6 million, excluding Lehman Brothers’ unfunded commitment.

~~Impact of Severe Weather~~

The economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in increased commodity prices. Additionally, severe weather may restrict or prevent us from fully utilizing our assets, by damaging our assets, interrupting utilities, and through possible NGL and natural gas curtailments downstream of our facilities, which restricts our production. These impacts may linger past the time of the actual weather event. Severe weather may also impact the supply and demand in our wholesale propane business.

~~Other Factors~~

Natural Gas Services Segment

Our results of operations for our Natural Gas Services segment are impacted by (1) increases and decreases in the volume and quality of natural gas that we gather and transport through our systems, which we refer to as throughput, (2) the associated Btu content of our system throughput and our related processing volumes, (3) the prices of and relationship between commodities such as NGLs, crude oil and natural gas, ~~(3)~~(4) the operating efficiency of our processing facilities, ~~and (4)~~(5) potential limitations on throughput volumes arising from downstream and infrastructure capacity ~~constraints.~~ constraints, and (6) the terms of our processing contract arrangements with producers.

Throughput and operating efficiency generally are driven by wellhead production, plant recoveries, operating availability of our facilities, physical integrity and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate. Historical and current trends in the price changes of commodities may not be indicative of future trends. Throughput and prices are also driven by demand and take-away capacity for residue natural gas and NGLs.

~~Natural Gas Services segment results of operations are also impacted by the fees we receive and the margins we generate.~~

Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, the commodity pricing environment at the time the contract is executed, customer requirements and ~~customer requirements.~~competition from other midstream service providers. Our gathering and processing contract mix and, accordingly, our exposure to natural gas, NGL and condensate prices, may change as a result of producer preferences, impacting our expansion in regions where certain types of contracts are more common ~~and~~as well as other market factors.

~~Additionally,~~

The capacity on certain downstream NGL and natural gas infrastructure has tightened in recent periods and can be further constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating our ~~results of operations for our~~facilities optimally.

Our Natural Gas Services segment operating results are impacted by market conditions causing variability in natural gas, crude oil and NGL prices. 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 correlated to the price of crude oil, except in recent periods, when NGL pricing has been at a greater discount to crude oil pricing.~~NGLs. 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~~explore and produce natural ~~gas exploration and production.~~ gas.

The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close ~~correlation. Changes~~relationship. Due to our hedging program, changes in the ~~correlation~~relationship of the price of NGLs and crude oil may cause our commodity price ~~sensitivities~~exposure to ~~vary.~~

~~While pricing impacts the Natural Gas Services segment,~~vary, which we have ~~mitigated a significant portion of the anticipated~~attempted to capture in our commodity price risk associated with the equity volumes from our gathering and processing operations, for both our consolidated entities and our proportionate share of exposure from our equity method investments, through 2013 with fixed price natural gas and crude oil swaps. We mark these derivative instruments to market through current period earnings based upon their fair value. While the swaps may mitigate the variability of our future cash flows resulting from changessensitivities in commodity prices, the mark-to-market method of accounting significantly increases the volatility of our net income because we recognize, in current period operating revenues, all non-cash gains and losses from the changes in the fair value of these derivatives. We primarily use crude oil swaps to mitigate our NGL and condensate commodity price risk. As a result, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. We also continue to have price risk exposure related to the portion of our equity volumes that are not covered by these derivatives and we have financial risk exposure to the extent our actual equity volumes differ from our projections. For additional information regarding our derivative activities, please read “— Quantitative and Qualitative Disclosures about Market ~~Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities.~~Risk.”

~~Based on historical trends, however, we generally expect NGL~~ Our results may also be impacted as a result of non-cash lower of cost or market inventory or imbalance adjustments, which occur when the market value of commodities decline below our carrying value.

The natural gas services business is highly competitive in our markets and includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices ~~to follow changes in~~for crude oil, prices over the long term, which we believe 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. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather, and the domestic production and drilling activity level of exploration and production companies. Drilling activity can be adversely affected asand/or natural gas ~~prices decrease. Energy market uncertainty could~~liquids. Competition is also

increased in those geographic areas where our commercial contracts with our customers are shorter in length of term and therefore must be renegotiated on a more frequent basis.

reduce North American drilling activity in the future. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall below demand levels.

Wholesale Propane Logistics Segment

Our ~~results of operations for our~~ Wholesale Propane Logistics segment operating results are impacted by our ability to ~~balance~~provide our ~~purchases and sales~~retail propane distribution customers with reliable supplies of ~~propane, which may increase our exposure to commodity price risks.~~propane. We ~~may mitigate a portion of the anticipated commodity price risk associated with fixed price propane sales by entering into either offsetting~~use physical inventory, physical purchase agreements orand financial derivative instruments, with DCP Midstream, LLC or third parties, which

typically match the quantities of propane subject to ~~these~~ fixed price sales ~~agreements.~~agreements to mitigate our commodity price risk. Our results may also be impacted as a result of non-cash lower of cost or market inventory adjustments, which occur when the market value of propane declines below our inventory value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory. There may be ~~an impact~~positive or negative impacts on sales volumes and gross margin from supply disruptions and weather conditions in the ~~midwest~~mid-atlantic, upper midwestern and northeastern areas of the United States. Our annual sales volumes of propane may decline when these areas experience periods of milder weather in the winter months. Volumes may also be impacted by conservation and reduced demand in ~~the current~~a recessionary environment.

The wholesale propane business is highly competitive in our market areas which include the mid-atlantic, upper midwest and northeastern regions of the United States. Our competitors include major integrated oil and gas and energy companies, and interstate and intrastate pipelines.

NGL Logistics Segment

Our ~~results of operations for our~~ NGL Logistics segment operating results are impacted by the throughput volumes of the NGLs we transport on our NGL pipelines asand the volumes of NGLs we store in our storage facility. We transport and store NGLs ~~exclusively~~primarily on a fee basis. Throughput may be negatively impacted as a result of our customers operating their processing plants in ethane rejection mode, often as a result of low commodity prices for ethane. ~~During the fourth quarter of 2008, we did experience reduced throughput due to ethane rejection at certain plants.~~ Factors that impact the supply and demand of NGLs, as described above in our Natural Gas Services segment, may also impact the throughput and volume for our NGL Logistics segment.

~~Other~~

~~The above factors, including further sustained deterioration in commodity prices, volumes or other market declines, including~~ Our results may also be impacted as a ~~decline in our unit price, may negatively impact our results~~result of ~~operations, and may increase the likelihood of a non-cash impairment charge or~~ non-cash lower of cost or market inventory ~~adjustments.~~

~~General Trends and Outlook~~

~~We expect~~adjustments, which occur when the market value of NGLs decline below 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.

carrying value.

~~Commodity Prices~~Weather— In the fourth quarter of 2008, natural gas, NGL and crude oil prices dropped significantly compared to prices in 2007 and the first three quarters of 2008. We are continuing to experience relatively lower commodity prices in 2009. Commodity prices are impacted by demand, which has been negatively impacted by the current recessionary environment.

~~Natural Gas Supply and Outlook~~— In the near term, softening of natural gas prices, reduced demand for natural gas and NGLs, potential reduction in available capital, and the recent downturn in the economy have had a moderating effect on levels of drilling activity.

The economic impact of ~~these factors will vary across~~severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in commodity price volatility. Additionally, severe weather may restrict or prevent us from fully utilizing our ~~broad geographic locations. Generally, we expect a decrease in drilling levels in 2009. The number of active oil~~assets, by damaging our assets, interrupting utilities, and gas rigs drilling in the United States was 364 and 1,347, respectively, at December 31, 2008, compared to 325 and 1,452, respectively, at December 31, 2007. Our long-term view is that natural gas prices will return to a level that would support the relatively higher levels of natural gas-related drilling experienced in recent years in the United States, as producers seek to increase their level of natural gas production. We believe that in the long-term an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

~~Additionally, the capacity on certain downstream~~through possible NGL and natural gas ~~infrastructure has tightened recently and can be further constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating~~curtailments downstream of our facilities, ~~optimally.~~

~~Processing Margins~~— ~~Except for~~which restricts our ~~fee-based contracts,~~production. These impacts may linger past the time of the actual weather event. Severe weather may also impact the supply availability and propane demand in our ~~processing profitability is dependent upon pricing~~Wholesale Propane Logistics segment. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and ~~market demand for natural gas, NGLs and condensate, which are beyond our control and~~in certain circumstances we have been ~~volatile. We~~unable to obtain insurance on commercially reasonable terms, if at all.

Capital Markets

Volatility in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to finance their drilling programs and limiting our ability to fund our operations through acquisitions or organic growth projects. These events may impact our counterparties’ ability to perform under their credit or commercial obligations. Where possible, we have ~~mitigated our cash flow exposure~~obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines, to ~~commodity price movements for these commodities by entering into derivative arrangements through 2013 for~~mitigate a ~~significant~~ portion of our currently anticipated natural gas, NGL and condensate commodity price risk associated with the equity volumes from our gathering and processing operations. For additional information regarding our derivative activities, please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities.”

these risks.

~~Wholesale Propane Supply and Outlook~~— We are a wholesale supplier of propane for the midwest and northeastern United States, which consists of Connecticut, Maine, Massachusetts, New Hampshire, New York, Ohio, Pennsylvania, Rhode Island and Vermont. Pipeline deliveries to this region in the winter season are generally at capacity and competing propane supply sources, generally consisting of open access propane terminals supplied by interstate pipelines, can have significant supply constraints or outages during peak market conditions. 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 periods of tight supply, such as the winter months when their retail customers consume the most propane for home heating.

~~Competition~~— The natural gas services business is highly competitive in our markets and includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport~~and/or~~ ~~market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gasand/or~~ natural gas liquids. Competition is also increased in those geographic areas where our commercial contracts with our customers are shorter in length of term and therefore must be renegotiated on a more frequent basis.

The wholesale propane business is highly competitive in the upper midwest and northeastern regions of the United States. Our wholesale propane business’ competitors include major integrated oil and gas and energy companies, and interstate and intrastate pipelines.

Impact of Inflation— ~~Our industry~~

Inflation has ~~experienced rising inflation due to increased activity~~been relatively low in the United States in recent years. However, the inflation rates impacting our business fluctuate throughout the broad economic and energy ~~sector.~~business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, ~~contract~~ labor and major equipment purchases ~~have increased. Recently however,~~may increase during periods of general business inflation or periods of relatively high energy commodity prices.

Other

The above factors, including sustained deterioration in commodity prices, volumes or other market declines, including a decline in our unit price, may negatively impact our results of operations, and may increase the likelihood of a non-cash impairment charge or non-cash lower of cost or market inventory adjustments.

Recent Events

In January 2011, we ~~have seen softening in certain costs. In~~announced that we are no longer pursuing a joint venture or alternative transaction structures with EQT Corporation.

On January 27, 2011, the future, we may again be affected by inflation. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the formboard of ~~higher fees.~~

~~2009 Outlook~~

~~Our focus in 2009 will be on the basics~~directors of the ~~business, including operating our assets well, being disciplined with~~general partner declared a quarterly distribution of $0.6175 per unit, payable on February 14, 2011 to unitholders of record on February 7, 2011.

On December 30, 2010, we acquired all ~~uses of funds and effectively managing our business risk and daily operations in a very uncertain and volatile business environment.~~

The restoration of our operations is nearing completion. Repairs to the Discovery system, which was damaged by the hurricanes in fall 2008, were substantially completed in January 2009. Approximately 85% of the ~~volumes~~interests in Marysville Hydrocarbons Holdings, LLC, or Marysville. The acquisition involved three separate transactions with a number of parties. The Partnership acquired a 90% interest in Marysville from Dart Energy Corporation, a 5% interest in Marysville from Prospect Street Energy, LLC and ~~margins have been returned~~100% of EE Group, LLC, which owns the remaining 5% interest in Marysville. We paid a purchase price of $94.8 million and $6.0 million for net working capital and other adjustments, for an aggregate purchase price of $100.8 million subject to ~~service,~~customary purchase price adjustments, for our 100% interest. The purchase was financed at closing with borrowings under the ~~remainder expected by early March. The Discovery distribution is paid one quarter in arrears. We do not expect to receive a distribution from Discovery during~~Partnership’s revolving credit facility. $21.2 million of the first quarter of 2009. We would expect to receive a distribution during the second quarter of 2009, commensurate with the partial restoration in January 2009, and a distribution during the third quarter of 2009, commensurate with the return to full service. The second phase of our Douglas pipeline integrity and system enhancement projectpurchase price has been ~~completed, returning over 80%~~deposited in an indemnity escrow to satisfy certain tax liabilities and provide for breaches of representations and warranties of the ~~system volumes to service by mid-January 2009. The final phase is on target for completion in March 2009.~~

sellers.

We are in the process of returning gas online following the fire caused by a third party pipeline rupture near our Carthage Hub, and expect it to be returned to normal service by the end of March 2009.

We will continue to execute on our two organic growth projects in the Piceance Basin and East Texas. We expect the remaining spending to be approximately $65.0 million in 2009, which will be funded through our existing credit facility.

~~We expect to close the transaction~~On November 4, 2010, we entered into agreements with DCP Midstream, LLC ~~in April 2009~~ to acquire ~~an additional 25.1%~~a 33.33% interest in ~~East Texas. We expect the transaction will be~~Southeast Texas for $150.0 million. The Southeast Texas system is a fully ~~financed through the issuance~~integrated midstream business which includes 675 miles of ~~3.5 million Class D units issued to DCP Midstream, LLC.~~natural gas pipelines, three natural gas processing plants with recently increased processing capacity totaling 380 MMcf/d and natural gas storage assets with 9 Bcf of existing storage capacity. The ~~transaction is expected to generate cash flow from operations of approximately $15.0 million over the first twelve month period following the close~~terms of the ~~transaction. As a part of the transaction, DCP Midstream, LLC is expected~~joint venture agreement provide that distributions to ~~provide a fixed price NGL derivative by component~~us for the first ~~twelve month period following the close of the transaction.~~

~~Cash flow assumptions for our 2009 outlook include a full year impact from our Michigan acquisition, an increase in cash flows during the second half of the year~~seven years related to ~~our Piceance Basin~~storage and ~~East Texas capital projects,~~transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and ~~maintenance capital of $10.0 million~~tailgate volumes. Distributions related to ~~$15.0 million, which includes~~ the ~~remaining spending~~gathering and processing business, along with reductions for ~~the Douglas pipeline integrity and system enhancement project. In total, we estimate the impact to cash flow in 2009 as a result of operations disruptions at Discovery and Douglas to~~all expenditures, will be ~~approximately $10.0 million to $12.0 million.~~

Our cash flows are expected to vary under various commodity price scenarios. However, the combination of our significant fee-based business, our highly hedged position and minimum fees in certain contracts provide downside protectionpursuant to our ~~cash flows.~~

~~Our percentage~~and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. This acquisition closed on January 1, 2011.

In November 2010, we issued 2,875,000 common units at $34.96 per unit. We received proceeds of ~~fee-based margins is expected to be approximately 56% in 2009. We have hedged approximately 80%~~$96.2 million, net of ~~our equity position in natural gas liquids, condensate and natural gas associated with the remainder of our expected margins that are not fee-based.~~

~~Based upon our business plan, we expect that our available capacity under our existing credit facility is sufficient to support our operating needs and capital program in 2009.~~

offering costs.

Our Operations

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

Natural Gas Services Segment

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


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

•

~~Percent-of-proceeds~~Percent-of-proceeds/liquids arrangements— Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and


		~~NGLs~~ condensate based on index prices from published index market prices. We remit

to the producers either anagreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and ~~NGLs,~~condensate, or anagreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and ~~the NGLs,~~condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in our returning all or a portion of the residue natural gasand/or the NGLs to the producer, in lieu of returning sales proceeds. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements ~~correlate~~relate directly with the price of natural gas,~~and/or~~ ~~NGLs.~~ NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.

In addition to the above contract types, we have keep-whole arrangements, which are estimated to generate less than 6% of our gross margin. Our equity method ~~investments~~investment in Discovery, also ~~generate equity earnings for our Natural Gas Services segment under~~has keep-whole arrangements. Under the terms of a keep-whole processing contract, ~~we gather~~ natural gas is gathered from the producer for processing, ~~sell~~ the NGLs and ~~return~~condensate are sold and the residue natural gas is returned to the producer ~~residue natural gas~~ with a Btu content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under this type of contract, we are exposed to the frac spread. The frac spread is the difference between the value of the NGLs and condensate extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL and condensate prices are higher relative to natural gas prices when that frac spread exceeds the operating ~~costs of our equity method investments.~~costs. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.

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

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

The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in Colorado, Louisiana, Michigan, Oklahoma, Texas, Wyoming and the Gulf of Mexico. The Pelico system also receives natural gas produced in Texas through its interconnect with other pipelines that transport natural gas from Texas into western Louisiana. These areas have historically experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. Our ~~two~~one primary ~~suppliers~~supplier of natural gas in our Natural Gas Services segment represented approximately ~~30%~~14% of the~~499 MMcf/d~~ of natural gas supplied to this system in ~~2008.~~2010. We actively seek new supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage, or by obtaining natural gas that has been directly received or released from other gathering systems.

In 2010, due to the decline in producer drilling in various areas in which we operate, new well connections have been at reduced levels.

We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to DCP Midstream, LLC or its affiliates, or to third parties. In addition, under our merchant arrangements, we use a subsidiary of DCP Midstream, LLC as our agent to purchase natural gas from third parties at pipeline interconnect points, as well as residue gas from our Minden and Ada processing plants, and then resell the aggregated natural gas to third parties. We also have entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that requires DCP Midstream, LLC to supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where

we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index based price less a contractually agreed to marketing fee. In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential plus a fixed fuel charge and other related adjustments. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing financial derivatives to swap this fixed price risk back to market index. We may enter into financial derivatives to lock in time spreads and price differentials across the Pelico system to maximize the value of pipeline and storage capacity. ~~These financial derivatives are accounted for using mark-to-market accounting.~~ We also gather, process and transport natural gas under fee-based transportation contracts.

Our Southeast Texas system also manages the value of pipeline and storage capacity in a similar manner, although our 33.33% distributions for the first seven years are fee-based such that we are not exposed to that activity.

Wholesale Propane Logistics Segment

We operate a wholesale propane logistics business in the mid-atlantic, upper midwest and northeastern United States. We purchase large volumes of propane supply from natural gas processing plants and fractionation facilities, and crude oil refineries, primarily located in the Texas and Louisiana Gulf Coast area, Canada and other international sources, and transport these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities in the ~~Midwest~~mid-atlantic, midwest and the northeastern areas of the United States. We identify primary suppliers as those individually representing 10% or more of our total propane supply. Our ~~three~~four primary suppliers of propane, two of which are affiliated entities, represented approximately ~~82%~~91% of our propane supplied in ~~2008.~~2010. We sell propane on a wholesale basis to retail propane distributors who in turn resell propane to their retail customers.

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

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

NGL Logistics Segment

Our pipelines and storage facility provide transportation and storage services for customers, primarily on a fee basis. We have entered into contractual arrangements with DCP Midstream, LLC and others that generally require ~~DCP Midstream, LLC~~customers to pay us to transport or store NGLs pursuant to a fee-based rate that is applied to ~~the volumes transported.~~volumes. Therefore, the results of

operations for this business segment are generally dependent upon the volume of product transported or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL ~~pipelines;~~pipelines or stored in our storage facility; rather, the ~~shipper~~customer retains title and the associated commodity price risk. ~~For~~DCP Midstream, LLC provides 100% of volumes transported on the Seabreeze and Wilbreeze ~~pipelines, we are responsible for any line loss or gain in NGLs.~~pipelines. For the Black Lake pipeline, any line loss or gain in NGLs is allocated to the shipper. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, ~~and will likely experience periods in the future,~~ in which higher natural gas prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. In the transportation markets we serve, our pipelines are the sole pipeline facility transporting NGLs from the supply source.

Our storage facility in Marysville, Michigan provides storage and related services primarily to depositories operating in the liquid hydrocarbons industry.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) volumes; (2) gross margin, segment gross margin and adjusted segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) ~~EBITDA and~~ adjusted EBITDA; and (5) distributable cash flow. Gross margin, segment gross margin, adjusted segment

gross margin, ~~EBITDA,~~ adjusted EBITDA and distributable cash flow ~~measurements~~ are not ~~GAAP financial measures. We provide~~measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent permitted, we present certain non-GAAP measures and reconciliations of ~~certain non-GAAP~~those measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP. These non-GAAP measures may not be comparable to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the same manner.

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

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, including commodity derivative activity, 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 commodity derivative losses, less non-cash commodity 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:

Year Ended December 31,
Reconciliation of Non-GAAP Measures
2008 2007 2006
(Millions)

Reconciliation of net income (loss) to gross margin:

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9
Interest expense 32.8 25.8 11.5
Income tax expense 0.1 0.1 —
Operating and maintenance expense 43.0 32.1 23.7
Depreciation and amortization expense 36.5 24.4 12.8
General and administrative expense 24.0 24.1 21.0
Other (1.5 ) — —
Non-controlling interest in income 3.9 0.5 —
Interest income (5.6 ) (5.3 ) (6.3 )
Earnings from equity method investments (34.3 ) (39.3 ) (29.2 )

Gross margin $ 224.6 $ 46.6 $ 95.4

Reconciliation of segment net income to segment gross margin:

Natural Gas Services segment:

Segment net income $ 170.2 $ 11.6 $ 79.6
Depreciation and amortization expense 33.8 21.9 11.1
Operating and maintenance expense 32.1 20.9 13.5
Non-controlling interest in income 3.9 0.5 —
Earnings from equity method investments (33.5 ) (38.7 ) (28.9 )

Segment gross margin $ 206.5 $ 16.2 $ 75.3

Non-cash commodity derivative mark-to-market(a) $ 99.2 $ (78.3 ) $ 0.1

Wholesale Propane Logistics segment:

Segment net income $ 1.3 $ 14.0 $ 6.6
Depreciation and amortization expense 1.3 1.1 0.8
Operating and maintenance expense 9.9 10.4 8.6
Other (1.5 ) — —

Segment gross margin $ 11.0 $ 25.5 $ 16.0

Non-cash commodity derivative mark-to-market(a) $ 2.4 $ (2.8 ) $ —

NGL Logistics segment:

Segment net income $ 5.5 $ 3.3 $ 1.9
Depreciation and amortization expense 1.4 1.4 0.9
Operating and maintenance expense 1.0 0.8 1.6
Earnings from equity method investments (0.8 ) (0.6 ) (0.3 )

Segment gross margin $ 7.1 $ 4.9 $ 4.1

Reconciliation of Non-GAAP Measures


	Year Ended December 31,
	2010			2009			2008
	(Millions)
Reconciliation of net income (loss) attributable to partners to gross margin:
Net income(loss) attributable to partners	$	48.0		$	(19.1	)	$	141.9
Interest expense		29.1			28.3			32.8
Income tax expense		0.3			0.6			0.6
Operating and maintenance expense		79.8			69.7			77.4
Depreciation and amortization expense		73.7			64.9			53.2
General and administrative expense		33.7			32.3			33.3
Other income		(1.0	)		—			(1.5	)
Other income — affiliate		(3.0	)		—			—
Step acquisition — equity interest re-measurement gain		(9.1	)		—			—
Interest income		—			(0.3	)		(6.1	)
Earnings from unconsolidated affiliates		(23.8	)		(18.5	)		(18.2	)
Net income attributable to noncontrolling interests		9.2			8.3			36.1

Gross margin	$	236.9		$	166.2		$	349.5

Non-cash commodity derivative mark-to-market(a)	$	(5.4	)	$	(83.4	)	$	101.6

Reconciliation of segment net income(loss) attributable to partners to segment gross margin:
*Natural Gas Services segment:*
Segment net income(loss) attributable to partners	$	77.3		$	(2.1	)	$	195.7
Operating and maintenance expense		63.5			58.2			66.5
Depreciation and amortization expense		69.1			61.9			50.5
Other income		(1.0	)		—			—
Earnings from unconsolidated affiliates		(23.0	)		(16.6	)		(17.4	)
Net income attributable to noncontrolling interests		9.2			8.3			36.1

Segment gross margin	$	195.1		$	109.7		$	331.4

Non-cash commodity derivative mark-to-market(a)	$	(4.4	)	$	(84.2	)	$	99.2

*Wholesale Propane Logistics segment:*
Segment net income attributable to partners	$	17.4		$	37.2		$	1.3
Operating and maintenance expense		12.6			10.3			9.9
Depreciation and amortization expense		1.9			1.4			1.3
Other income		—			—			(1.5	)
Other income — affiliate		(3.0	)		—			—

Segment gross margin	$	28.9		$	48.9		$	11.0

Non-cash commodity derivative mark-to-market(a)	$	(1.0	)	$	0.8		$	2.4

*NGL Logistics segment:*
Segment net income attributable to partners	$	16.5		$	6.9		$	5.5
Operating and maintenance expense		3.7			1.2			1.0
Depreciation and amortization expense		2.6			1.4			1.4
Step acquisition – equity interest re-measurement gain		(9.1	)		—			—
Earnings from unconsolidated affiliates		(0.8	)		(1.9	)		(0.8	)

Segment gross margin	$	12.9		$	7.6		$	7.1


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

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

~~A substantial amount of our general~~ General and administrative ~~expense is incurred from DCP Midstream, LLC.~~ expenses are as follows:


	Year Ended December 31,
	2010		2009		2008
Affiliate:
Omnibus Agreement	$	9.9	$	9.7	$	9.8
Other — DCP Midstream, LLC		9.3		10.4		10.4
Other — affiliate		0.2		0.3		—

Total affiliate		19.4		20.4		20.2
Third Party		14.3		11.9		13.1

Total	$	33.7	$	32.3	$	33.3

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 salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. ~~The fees under the Omnibus Agreement increased $0.4 million per year effective October 1, 2008, in connection with the acquisition of MPP.~~ We also pay DCP Midstream, LLC an annual fee under the Omnibus Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. ~~Under~~

On January 1, 2011, we extended the ~~Omnibus Agreement, DCP Midstream, LLC provided parental guarantees, totaling $43.0 million at~~omnibus agreement through December 31, ~~2008, to certain counterparties to our commodity derivative instruments.~~

~~Our total general and administrative expense was comprised of the following:~~

Year Ended December 31,
2008 2007 2006

Affiliate:
Omnibus Agreement:
Annual fee $ 5.1 $ 5.0 $ 4.8
Wholesale propane logistics business 2.0 2.0 0.3
Southern Oklahoma 0.2 0.1 —
Discovery 0.2 0.1 —
Additional services 0.6 0.2 —
Momentum Energy Group, Inc. 1.6 0.5 —
Michigan Pipeline & Processing, LLC 0.1 — —

Total Omnibus Agreement 9.8 7.9 5.1
Other — DCP Midstream, LLC 1.8 2.1 3.0

Total affiliate 11.6 10.0 8.1
Other 12.4 14.1 12.9

Total $ 24.0 $ 24.1 $ 21.0

~~Following is a summary of the fees we anticipate incurring in 2009 under the Omnibus Agreement and the effective date~~2011 for ~~these fees:~~

Terms
Effective Date Fee
(Millions)

Annual fee 2006 $ 5.1
Wholesale propane logistics business November 2006 2.0
Southern Oklahoma May 2007 0.2
Discovery July 2007 0.2
Additional services August 2007 0.6
Momentum Energy Group, Inc. August 2007 1.6
Michigan Pipeline & Processing, LLC October 2008 0.4

Total $ 10.1

$10.2 million. The Omnibus Agreement also addresses the following matters:

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


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

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

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

~~All~~ of ~~the fees under the Omnibus Agreement will be adjusted annually by the percentage change in the Consumer Price Index for the applicable year. In addition, our~~such contracts; and

Our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses, with the concurrence of the special committee of DCP Midstream GP, LLC’s board of directors.

~~Other~~

East Texas incurs general and administrative expenses ~~paid to~~directly from DCP Midstream, LLC. During the years ended December 31, 2010, 2009 and 2008, East Texas incurred $7.8 million, $8.5 million and $8.6 million, respectively, for general and administrative expenses from DCP Midstream, LLC, ~~subsequent to~~which includes expenses for our ~~initial public offering include labor~~predecessor operations.

Outside of the Omnibus Agreement and ~~benefit costs related to accounting and internal audit personnel, insurance as well as~~amounts incurred by East Texas, we incurred other ~~administrative costs. Additionally,~~fees with DCP Midstream, LLC, ~~provided centralized corporate functions on behalf of~~which includes expenses for our predecessor operations, of $1.5 million, $1.9 million and $1.8 million, respectively, for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts include allocated expenses, including ~~legal, accounting, cash management,~~professional services, insurance ~~administration~~ and ~~claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll,~~ internal audit, taxes and engineering. The predecessor’s share of those costs was allocated based on the predecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investments, and intangible assets, net) as compared to DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used were reasonable and resulted in an allocation to the predecessors of their respective costs of doing business, which were borne by DCP Midstream, LLC.

audit.

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

~~EBITDA,~~ 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, ~~and~~ depreciation and amortization ~~expense. We define adjusted EBITDA as EBITDA plus~~

expense and non-cash commodity derivative ~~losses, less non-cash commodity derivative gains.~~losses. Adjusted EBITDA ~~and adjusted EBITDA are~~is used as a supplemental liquidity and performance ~~measures~~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.~~

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

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

Our ~~EBITDA and~~ adjusted EBITDA may not be comparable to a similarly titled ~~measures~~measure of another company because other entities may not calculate ~~these measures~~this measure in the same manner. ~~As discussed in the Liquidity and Capital Resources section below, our credit facility also defines EBITDA, which is used in evaluating our compliance with our financial covenants.~~

~~EBITDA and adjusted~~

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. ~~The following table sets forth reconciliations of EBITDA from its most directly comparable financial measures calculated in accordance with GAAP:~~

Year Ended December 31,
Reconciliation of Non-GAAP Measures
2008 2007 2006
(Millions)

Reconciliation of net income (loss) to EBITDA:

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9
Interest income (5.6 ) (5.3 ) (6.3 )
Interest expense 32.8 25.8 11.5
Income tax expense 0.1 0.1 —
Depreciation and amortization expense 36.5 24.4 12.8

EBITDA $ 189.5 $ 29.2 $ 79.9

Reconciliation of net cash provided by operating activities to EBITDA:

Net cash provided by operating activities $ 101.5 $ 65.4 $ 94.8
Interest income (5.6 ) (5.3 ) (6.3 )
Interest expense 32.8 25.8 11.5
Earnings from equity method investments, net of distributions (25.6 ) 0.4 3.3
Income tax expense 0.1 0.1 —
Net changes in operating assets and liabilities 89.8 (56.9 ) (25.8 )
Other, net (3.5 ) (0.3 ) 2.4

EBITDA $ 189.5 $ 29.2 $ 79.9

We define ~~distributable cash flow~~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, ~~non-controlling~~net income attributable to noncontrolling interest onnet 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~~Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices. Distributable ~~cash flow~~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~~Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate ~~distributable cash flow~~Distributable Cash Flow in the same manner.

~~Critical Accounting Policies and Estimates~~

Our financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”


		~~Effect if Actual Results Differ from~~
~~Description~~	~~Judgments and Uncertainties~~	~~Assumptions~~

~~Inventories~~
~~Inventories, which consist primarily of propane, are recorded at the lower of weighted-average cost or market value.~~	Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory.	If the market value of our inventory is lower than the cost, we may be exposed to losses that could be material. If propane prices were to decrease by 10% below our December 31, 2008 weighted-average cost, our net income would be affected by approximately $2.1 million.
~~Goodwill~~
Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	We completed our impairment testing of goodwill using the methodology described herein, and determined there was no impairment. We have not recorded goodwill impairment during the year ended December 31, 2008. The carrying value of goodwill as of December 31, 2008 was $88.8 million.
~~Impairment of Long-Lived Assets~~
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.	Our impairment analyses may require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. These techniques are also used when allocating the purchase price to acquired assets and liabilities.	Using the impairment review methodology described herein, we have not recorded impairment charges during the year ended December 31, 2008. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. The carrying value of our long-lived assets as of December 31, 2008 was $677.0 million.


		~~Effect if Actual Results Differ from~~
~~Description~~	~~Judgments and Uncertainties~~	~~Assumptions~~

~~Impairment of Equity Method Investments~~
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred.	Our impairment loss calculations require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models.	Using the impairment review methodology described herein, we have not recorded impairment charges during the year ended December 31, 2008. If the estimated fair value of our equity method investments is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value. The carrying value of our equity method investments as of December 31, 2008 was $175.4 million.
~~Accounting for Risk Management Activities and Financial Instruments~~
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions.	When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.	If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2008 would have affected net income by approximately $2.0 million for the year ended December 31, 2008.
~~Accounting for Equity-Based Compensation~~
Our long-term incentive plan permits for the grant of restricted units, phantom units, unit options and substitute awards. Equity-based compensation expense is recognized over the vesting period or service period of the related awards. We estimate the fair value of each award, and the number of awards that will ultimately vest, at the end of each period.	Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period.	~~If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in compensation expense.~~


		~~Effect if Actual Results Differ from~~
~~Description~~	~~Judgments and Uncertainties~~	~~Assumptions~~

~~Accounting for Asset Retirement Obligations~~
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled.	Estimating the fair value of asset retirement obligations requires management to apply judgment to evaluate the necessary retirement activities, estimate the costs to perform those activities, including the timing and duration of potential future retirement activities, and estimate the risk free interest rate. When making these assumptions, we consider a number of factors, including historical retirement costs, the location and complexity of the asset and general economic conditions.	If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in our asset retirement obligations. Establishing an asset retirement obligation has no initial impact on net income. A 10% change in depreciation and accretion expense associated with our asset retirement obligations during the year ended December 31, 2008, would not have had a significant effect on net income.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2010, 2009 and 2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

Variance
Variance

2008 vs. 2007 2007 vs. 2006
Year Ended December 31, Increase
Increase

2008(a) 2007(a) 2006 (Decrease) Percent (Decrease) Percent
(Millions, except as indicated)

Operating revenues:
Natural Gas Services(b) $ 791.5 $ 404.1 $ 415.3 $ 387.4 96 % $ (11.2 ) (3 )%
Wholesale Propane Logistics 483.0 459.6 375.2 23.4 5 % 84.4 23 %
NGL Logistics 11.3 9.6 5.3 1.7 18 % 4.3 81 %

Total operating revenues 1,285.8 873.3 795.8 412.5 47 % 77.5 10 %

Gross margin(c):
Natural Gas Services 206.5 16.2 75.3 190.3 1,175 % (59.1 ) (78 )%
Wholesale Propane Logistics 11.0 25.5 16.0 (14.5 ) (57 )% 9.5 59 %
NGL Logistics 7.1 4.9 4.1 2.2 45 % 0.8 20 %

Total gross margin 224.6 46.6 95.4 178.0 382 % (48.8 ) (51 )%
Operating and maintenance expense (43.0 ) (32.1 ) (23.7 ) 10.9 34 % 8.4 35 %
General and administrative expense (24.0 ) (24.1 ) (21.0 ) (0.1 ) — % 3.1 15 %
Other 1.5 — — 1.5 * — — %
Earnings from equity method investments(d) 34.3 39.3 29.2 (5.0 ) (13 )% 10.1 35 %
Non-controlling interest in income (3.9 ) (0.5 ) — 3.4 680 % 0.5 100

EBITDA(e) 189.5 29.2 79.9 160.3 549 % (50.7 ) (64 )%
Depreciation and amortization expense (36.5 ) (24.4 ) (12.8 ) 12.1 50 % 11.6 91 %
Interest income 5.6 5.3 6.3 0.3 6 % (1.0 ) 16 %
Interest expense (32.8 ) (25.8 ) (11.5 ) 7.0 27 % 14.3 *
Income tax expense (0.1 ) (0.1 ) — — — % 0.1 100 %

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9 $ 141.5 * $ (77.7 ) *

Operating data:
Natural gas throughput(MMcf/d)(d)
838 756 666 82 11 % 90 14 %
NGL gross production (Bbls/d)(d) 20,659 22,122 19,485 (1,463 ) (7 )% 2,637 14 %
Propane sales volume (Bbls/d) 21,053 22,798 21,259 (1,745 ) (8 )% 1,539 7 %
NGL pipelines throughput (Bbls/d)(d) 31,407 28,961 25,040 2,446 8 % 3,921 16 %


										Variance 2010 vs. 2009						Variance 2009 vs. 2008
	Year Ended December 31,									Increase (Decrease)			Percent			Increase (Decrease)			Percent
	2010(a)(b)			2009(a)(b)			2008(a)(b)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services(c)	$	778.7		$	583.7		$	1,336.2		$	195.0			33	%	$	(752.5	)		(56	)%
Wholesale Propane Logistics		473.2			348.2			483.0			125.0			36	%		(134.8	)		(28	)%
NGL Logistics		17.6			10.5			11.3			7.1			68	%		(0.8	)		(7	)%

Total operating revenues		1,269.5			942.4			1,830.5			327.1			35	%		(888.1	)		(49	)%

Gross margin(d):
Natural Gas Services		195.1			109.7			331.4			85.4			78	%		(221.7	)		(67	)%
Wholesale Propane Logistics		28.9			48.9			11.0			(20.0	)		(41	)%		37.9			345	%
NGL Logistics		12.9			7.6			7.1			5.3			70	%		0.5			7	%

Total gross margin		236.9			166.2			349.5			70.7			43	%		(183.3	)		(52	)%
Operating and maintenance expense		(79.8	)		(69.7	)		(77.4	)		10.1			14	%		(7.7	)		(10	)%
Depreciation and amortization expense		(73.7	)		(64.9	)		(53.2	)		8.8			14	%		11.7			22	%
General and administrative expense		(33.7	)		(32.3	)		(33.3	)		1.4			4	%		(1.0	)		(3	)%
Step acquisition — equity interest re-measurement gain		9.1			—			—			9.1			100	%		—			—	%
Other income		1.0			—			1.5			1.0			100	%		(1.5	)		(100	)%
Other income — affiliates		3.0			—			—			3.0			100	%		—			—	%
Earnings from unconsolidated affiliates(e)		23.8			18.5			18.2			5.3			29	%		0.3			2	%
Interest income		—			0.3			6.1			(0.3	)		(100	)%		(5.8	)		(95	)%
Interest expense		(29.1	)		(28.3	)		(32.8	)		0.8			3	%		(4.5	)		(14	)%
Income tax expense		(0.3	)		(0.6	)		(0.6	)		(0.3	)		(50	)%		—			—	%
Net income attributable to noncontrolling interests		(9.2	)		(8.3	)		(36.1	)		0.9			11	%		(27.8	)		(77	)%

Net income (loss) attributable to partners	$	48.0		$	(19.1	)	$	141.9		$	67.1			*		$	(161.0	)		*

Other data:
Non-cash commodity derivative mark-to-market	$	(5.4	)	$	(83.4	)	$	101.6		$	78.0			94	%	$	(185.0	)		*
Natural gas throughput (MMcf/d)(e)		1,168			1,072			961			96			9	%		111			12	%
NGL gross production (Bbls/d)(e)		33,521			28,831			28,000			4,690			16	%		831			3	%
Propane sales volume (Bbls/d)		22,350			22,278			21,053			72			—	%		1,225			6	%
NGL pipelines throughput (Bbls/d)(e)		38,282			30,160			31,407			8,122			27	%		(1,247	)		(4	)%


*		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, and the results of Michigan Pipeline & Processing, LLC, or MPP, ~~Momentum Energy Group, Inc, or MEG, and Southern Oklahoma acquisitions, from their respective~~since October 1, 2008, the date of acquisition, ~~dates of October 2008, August 2007 and May 2007.~~in our Natural Gas Services Segment.

Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition, in our Wholesale Propane Logistics segment.

Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, 2010, the date of acquisition, in our NGL Logistics segment. The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

The impact to our results related to Marysville, acquired on December 30, 2010, is not significant.

(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. We do not utilize commodity derivative instruments for the proportionate interest in East Texas that is owned by DCP Midstream, LLC. As such, the portion of East Texas owned by DCP Midstream, LLC is unhedged. 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 corresponding with DCP Midstream, LLC’s ownership interest in East Texas in each period.

(c)

Includes the effect of the acquisition of the ~~Swap entered into~~NGL Hedge, contributed by DCP Midstream, LLC, in April 2009. The NGL Hedge was a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March ~~2007.~~2010. The ~~Swap~~NGL Hedge was for a total of ~~approximately~~ 1.9 million barrels at $66.72 per barrel.


~~(c)~~	(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 “How We Evaluate Our Operations” above.


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


~~(e)~~		~~EBITDA consists~~For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net ~~income or loss less interest income plus interest expense, income tax expense,~~difference between the carrying amount of the investment and ~~depreciation and amortization expense. Please read “How We Evaluate Our Operations” above.~~the underlying equity of the investment.

Year Ended December 31, ~~2008~~2010 vs. Year Ended December 31, ~~2007~~2009

Total Operating Revenues — Total operating revenues increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily as a result of the following:

$126.6 million increase primarily attributable to higher propane prices and our acquisition of Atlantic Energy in July 2010, which impact both sales and purchases, partially offset by a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather;

$122.7 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, and an increase in NGL production, partially offset by changes in contract mix, increased fuel consumption, differences in gas quality, 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 ~~following:~~first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project;

$57.3 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $77.5 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $20.2 million due to generally higher average prices of commodities in 2010; and


	•	$213.7 million increase primarily attributable to increased commodity prices as well as higher natural gas, NGL and condensate sales volumes, primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes, for our Natural Gas Services segment;

	•	~~$156.8 million increase related to commodity derivative activity, resulting from the following:~~

$20.1 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, our acquisition of an additional 50% interest in Black Lake, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts.


	•	we had a gain of $72.3 million in 2008 and a loss of $87.6 million in 2007, resulting in an increase of $159.9 million, which is included in gains (losses) from commodity derivative activity. This increase includes an increase in unrealized gains of $184.1 million due to forward prices of commodities generally being lower at the end of the year 2008 compared to 2007. Offsetting this increase in gain was an increase in realized cash settlement losses of $24.2 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007; and

	•	~~we had a $3.1 million increase in unrealized loss, which is included in sales of natural gas, NGLs and condensate;~~


	•	~~$22.1 million increase in transportation processing and other revenue, primarily attributable to the MEG and MPP acquisitions in our Natural Gas Services segment;~~

	•	~~$19.0 million increase attributable to higher propane prices offset by decreased propane sales volumes as a result of lower demand for our Wholesale Propane Logistics segment; and~~

	•	~~$0.9 million increase due to increased throughput volumes, transportation, processing and other revenue, and increases related to settlement of pipeline imbalances in our NGL logistics segment.~~

Gross Margin — Gross margin increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily as a result of the following:

$85.4 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, our organic growth project in the Piceance Basin and the renegotiation of commodity sensitive contracts to fee-based contracts, partially offset by reduced natural gas basis spreads, increased fuel consumption, decreased natural gas volumes and differences in gas quality 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 ~~following:~~


	•	~~$190.3 million increase for our Natural Gas Services segment primarily due to increases related to commodity derivative activity, an increase in natural gas, NGL~~first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and operational downtime; and ~~condensate production, mainly as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes; and~~

	•	~~$2.2 million increase for our NGL Logistics segment primarily attributable to increases related to settlement of pipeline imbalances and increased throughput volumes; partially offset by~~

	•	$14.5 million decrease for our Wholesale Propane Logistics segment as a result of increased non-cash lower of cost or market inventory adjustments due to a decline in propane prices in the second half of 2008. We estimate that approximately half of the 2008 write downs were recovered through the sale of inventory in 2008. We also had lower per unit margins and propane sales volumes, partially offset by commodity derivative activity.

$5.3 million increase for our NGL Logistics segment as a result of higher volumes from our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

These increases were partially offset by:

$20.0 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.

Operating and Maintenance Expense — Operating and maintenance expense increased in ~~2008~~2010 compared to ~~2007,~~2009 primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our capital projects completed in 2009, our Michigan acquisition, our Atlantic Energy acquisition, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain— Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake, bringing our ownership interest in Black Lake to 100% in our NGL Logistics segment. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the ~~MEG, MPP~~equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and ~~Southern Oklahoma~~recognized a gain of $9.1 million.

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 includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption and differences in gas quality at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

Year Ended December 31, 2009 vs. Year Ended December 31, 2008

Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:

$622.2 million decrease primarily attributable to decreased commodity prices, which impact both sales and purchases, and a decrease in natural gas sales volumes across certain assets. 2009 results include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas. Results in both years were impacted by hurricanes and operational downtime for our Natural Gas Services segment;

$137.5 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $184.8 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $47.3 million due to generally lower average prices of commodities in 2009;

$134.9 million decrease primarily attributable to lower propane prices, which impact both sales and purchases, partially offset by increased sales volumes, for our Wholesale Propane Logistics segment; and

$2.4 million decrease due primarily to lower NGL throughput volumes partially offset by increased per unit margins, for our NGL Logistics segment.

These decreases were partially offset by:

$9.1 million increase in transportation processing and other revenue, which represents our fee-based revenue, primarily attributable to increased throughput volumes due to our Michigan acquisitions, partially offset by decreases in throughput volumes across other assets.

Gross Margin — Gross margin decreased in 2009 compared to 2008, primarily due to the following:

$221.7 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity, lower commodity prices and lower natural gas volumes across certain assets. These decreases include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. The decreases were partially offset by ~~decreased property taxes~~increased fee-based throughput volumes due to our Michigan acquisitions. Results in both years were impacted by hurricanes and operational downtime.

These decreases were partially offset by:

$37.9 million increase for our Wholesale Propane Logistics ~~segment.~~segment as a result of increased volumes and margins, a portion of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

$0.5 million increase for our NGL Logistics segment, primarily due to higher per-unit margins.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by increased expenses as a result of the Michigan acquisitions.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2009 compared to 2008, primarily as a result of our Michigan acquisitions and our East Texas, Wyoming and Piceance Basin capital projects.

General and Administrative Expense — General and administrative expense decreased in ~~2008~~2009 compared to ~~2007, primarily due to acquisition-related costs incurred in 2007 and decreased compensation and benefits in~~ 2008, ~~partially offset by increased legal expenses in 2008.~~

~~Earnings from Equity Method Investments~~ — Earnings from equity method investments decreased in 2008 compared to 2007, primarily due to decreased equity earnings of $6.7 million from Discovery due primarily to hurricanes, as discussed in the Natural Gas Services Segment section below, partially offset by increased equity earnings of $1.5 million from East Texas and $0.2 million from Black Lake.

~~Non-Controlling Interest in Income~~ — Non-controlling interest in income reduced income by $3.9 million and $0.5 million in 2008 and 2007, respectively, and represents the non-controlling interest holders’ portion of the net income of our Collbran Valley Gas Gathering system joint venture, acquired in the MEG acquisition and in 2008 also includes the non-controlling interest holders’ portion of the net income of Jackson Pipeline Company, acquired in the MPP acquisition.

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

~~Interest Expense~~ ~~— Interest expense increased in 2008 compared to 2007, primarily as a result of financing acquisitions,~~our cost reduction initiatives, partially offset by ~~lower average interest rates.~~

~~Year Ended December 31, 2007 vs. Year Ended December 31, 2006~~our Michigan acquisitions.

~~Total Operating Revenues~~ ~~— Total operating revenues increased in 2007 compared to 2006, primarily due to the following:~~


	•	~~$88.1 million increase attributable to higher propane prices and higher sales volumes for our Wholesale Propane Logistics segment;~~

	•	$66.2 million increase primarily attributable to an increase in natural gas, NGL and condensate sales volumes, including increases as a result of the MEG and Southern Oklahoma acquisitions, and increases in NGL and condensate prices, partially offset by a decrease in natural gas sales volumes, primarily as a result of an amendment to a contract with an affiliate in 2006, which resulted in a prospective change in the reporting of certain Pelico revenues from a gross presentation to a net presentation for our Natural Gas Services segment;

	•	~~$7.3 million increase in transportation processing and other revenue primarily attributable to an increase in throughput volumes in our Natural Gas Services segment; and~~

	•	~~$3.4 million increase due to changes in product mix and increased volumes for our NGL Logistics segment; offset by~~

	•	$87.5 million decrease related to commodity derivative activity, an increase of $0.2 million which is included in sales of natural gas, NGLs and condensate, and a decrease of $87.7 million which is included in losses from derivative activity.

~~Gross Margin~~ ~~— Gross margin decreased in 2007 compared to 2006, primarily due to the following:~~


	•	$59.1 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity, and a decrease in marketing margins from the decline in the differences of natural gas prices at various receipt and delivery points across our Pelico system, offset by an increase in NGL and condensate production, mainly as a result of the MEG and Southern Oklahoma acquisitions, an increase in natural gas throughput volumes and higher contractual fees charged to customers; offset by


	•	$9.5 million increase for our Wholesale Propane Logistics segment due to higher per unit margins as a result of changes in contract mix and the ability to capture lower priced supply sources, decreased non-cash lower of cost or market inventory adjustments recognized in 2007, and higher sales volumes primarily due to the completion of the Midland terminal, which became operational in May 2007, partially offset by a decrease related to commodity derivative activity; and

	•	~~$0.8 million increase for our NGL Logistics segment primarily attributable to changes in product mix and increased volumes, as well as increased transportation processing and other revenue.~~

~~Operating and Maintenance Expense~~ — Operating and maintenance expense increased in 2007 compared to 2006, primarily as a result of the MEG and Southern Oklahoma acquisitions, higher labor and benefits and pipeline integrity costs in our Natural Gas Services segment, and higher operating and maintenance expense at the Midland terminal, which became operational in May 2007 in our Wholesale Propane Logistics segment, offset by lower pipeline integrity costs on our Seabreeze pipeline in our NGL Logistics segment.

~~General and Administrative Expense~~ — General and administrative expense increased in 2007 compared to 2006, primarily as a result of increased due diligence and acquisition costs, increased fees under our omnibus agreement with DCP Midstream, LLC and increased labor and benefit costs, partially offset by decreases in audit and public company costs.

Earnings from ~~Equity Method Investments~~Unconsolidated Affiliates — Earnings from ~~equity method investments~~unconsolidated affiliates increased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to increased ~~equity~~ earnings ~~of $7.2 million~~ from ~~Discovery, $2.6 million~~Black Lake, partially offset by decreased 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 decreased in 2009 primarily due to lower earnings at East Texas, ~~and $0.3 million from Black Lake.~~

~~Non-Controlling Interest~~for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a third party owned pipeline rupture, resulting in ~~Income~~ — Non-controlling interest in income reduced income by $0.5 million in 2007, and represents the non-controlling interest holders’ portion of the net income of our Collbran Valley Gas Gathering system joint venture, acquired in the MEG acquisition.

~~Depreciation and Amortization Expense~~ ~~— Depreciation and amortization expense increased in 2007 compared to 2006, primarily as~~ a ~~result of acquisitions.~~

~~Interest Expense~~ ~~— Interest expense increased in 2007 compared to 2006, primarily as a result of financing the 2007 acquisitions.~~

fire at East Texas.

Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system, ~~acquired in May 2007, a 25% limited liability company interest in East Texas,~~ a 40% limited liability company interest in Discovery, ~~and the Swap, acquired in July 2007,~~ our Colorado and Wyoming systems, ~~acquired in August 2007~~our East Texas systems, and our Michigan ~~systems, acquired in October 2008.~~

Variance
Variance

2008 vs. 2007 2007 vs. 2006
Year Ended December 31, Increase
Increase

2008(a) 2007(a) 2006 (Decrease) Percent (Decrease) Percent
(Millions, except operating data)

Operating revenues:
Sales of natural gas, NGLs and condensate $ 668.8 $ 458.2 $ 391.8 $ 210.6 46 % $ 66.4 17 %
Transportation, processing and other 50.2 29.4 23.5 20.8 71 % 5.9 25 %
Gains (losses) from commodity derivative activity(b) 72.5 (83.5 ) — 156.0 * (83.5 ) *

Total operating revenues 791.5 404.1 415.3 387.4 96 % (11.2 ) (3 )%
Purchases of natural gas and NGLs 585.0 387.9 340.0 197.1 51 % 47.9 14 %

Segment gross margin(c) 206.5 16.2 75.3 190.3 1,175 % (59.1 ) (79 )%
Operating and maintenance expense (32.1 ) (20.9 ) (13.5 ) 11.2 54 % 7.4 55 %
Depreciation and amortization expense (33.8 ) (21.9 ) (11.1 ) 11.9 54 % 10.8 97 %
Earnings from equity method investments(d) 33.5 38.7 28.9 (5.2 ) (13 )% 9.8 34 %
Non-controlling interest in income (3.9 ) (0.5 ) — 3.4 680 % 0.5 100 %

Segment net income $ 170.2 $ 11.6 $ 79.6 $ 158.6 1,367 % $ (68.0 ) (85 )%

Operating data:
Natural gas throughput(MMcf/d)(d)
838 756 666 82 11 % 90 14 %
NGL gross production (Bbls/d) 20,659 22,122 19,485 (1,463 ) (7 )% 2,637 14 %

system.


										Variance 2010 vs. 2009					Variance 2009 vs. 2008
	Year Ended December 31,									Increase (Decrease)		Percent			Increae (Decrease)			Percent
	2010(a)(b)			2009(a)(b)			2008(a)(b)			Increase (Decrease)		Percent			Increae (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	684.2		$	562.8		$	1,185.2		$	121.4		22	%	$	(622.4	)		(53	)%
Transportation, processing and other		102.1			87.3			79.1			14.8		17	%		8.2			10	%
(Losses) gains from commodity derivative activity(c)		(7.6	)		(66.4	)		71.9			58.8		89	%		(138.3	)		*

Total operating revenues		778.7			583.7			1,336.2			195.0		33	%		(752.5	)		(56	)%
Purchases of natural gas and NGLs		583.6			474.0			1,004.8			109.6		23	%		(530.8	)		(53	)%

Segment gross margin(d)		195.1			109.7			331.4			85.4		78	%		(221.7	)		(67	)%
Operating and maintenance expense		(63.5	)		(58.2	)		(66.5	)		5.3		9	%		(8.3	)		(12	)%
Depreciation and amortization expense		(69.1	)		(61.9	)		(50.5	)		7.2		12	%		11.4			23	%
Other income		1.0			—			—			1.0		100	%		—			—	%
Earnings from unconsolidated affiliates(e)		23.0			16.6			17.4			6.4		39	%		(0.8	)		(5	)%

Segment net income		86.5			6.2			231.8			80.3		1,295	%		(225.6	)		(97	)%
Segment net income attributable to noncontrolling interests		(9.2	)		(8.3	)		(36.1	)		0.9		11	%		(27.8	)		(77	)%

Segment net income (loss) attributable to partners	$	77.3		$	(2.1	)	$	195.7		$	79.4		*		$	(197.8	)		*

Other data:
Natural gas throughput (MMcf/d)(e)		1,168			1,072			961			96		9	%		111			12	%
NGL gross production (Bbls/d)(e)		33,521			28,831			28,000			4,690		16	%		831			3	%


*		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 ~~MEG,~~date of acquisition, and the results of MPP ~~and Southern Oklahoma acquisitions, from their respective acquisition dates~~since October 1, 2008, the date of ~~October 2008, August 2007 and May 2007.~~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 ~~Swap entered into~~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 ~~2007. The Swap was for a total of approximately 1.9 million barrels through 2012, at $66.72 per barrel.~~2010.


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


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

Year Ended December 31, ~~2008~~2010 vs. Year Ended December 31, ~~2007~~2009

Total Operating Revenues — Total operating revenues increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily as a result of the following:

$144.5 million increase attributable to increased commodity prices, which impact both sales and purchases;

$58.8 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $79.4 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $20.6 million due to generally higher average prices of commodities in 2010;

$30.0 million increase as a result of increased NGL production and a change to a contract with an affiliate in the ~~following:~~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; and

$14.8 million increase primarily as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets.


	•	~~$152.9 million increase related to commodity derivative activity, resulting from the following:~~

These increases were partially offset by:

$53.5 million decrease due primarily to the impact of changes in contract mix, increased fuel consumption, differences in gas quality, a decrease in natural gas sales volume across certain of assets, as well as 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 third party owned pipeline rupture, resulting in a fire at East Texas, and our Wyoming pipeline integrity and system enhancement project.


	•	we had a gain of $72.5 million in 2008 and a loss of $83.5 million in 2007, resulting in an increase of $156.0 million, which is included gains (losses) from commodity derivative activity. This increase includes an increase in unrealized gains of $178.8 million due to forward prices of commodities generally being lower at the end of the year 2008 compared to 2007. Offsetting this increase in gain was an increase in realized cash settlement losses of $22.8 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007; and

	•	~~we had a $3.1 million increase in unrealized loss, which is included in sales of natural gas, NGLs and condensate;~~


	•	~~$150.3 million increase attributable to increased commodity prices;~~

	•	$63.4 million increase attributable to higher natural gas, NGL and condensate sales volumes, primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes; and

	•	~~$20.8 million increase in transportation, processing and other revenue as a result of the MEG and MPP acquisitions.~~

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in ~~2008~~2010 compared to ~~2007, primarily due to increased natural gas purchase volumes~~2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a change to a contract with an affiliate in the ~~MEG, MPP~~Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and ~~Southern Oklahoma acquisitions, and higher costs~~other to a gross presentation in purchases of natural gas ~~supply, driven by higher commodity prices.~~

and NGLs.

Segment Gross Margin — Segment gross margin increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily as a result of the following:

$58.8 million increase related to commodity derivative activities as discussed in the Operating Revenues section above;

$31.2 million increase as a result of higher commodity prices; and


	•	~~$152.9 million increase related to commodity derivative activity, as discussed in the Operating Revenues section above;~~

	•	$24.1 million increase primarily attributable to an increase in natural gas, NGL and condensate production as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes;

	•	~~$9.0 million increase primarily attributable to changes in contract mix; and~~

	•	~~$4.3 million increase due to higher commodity prices.~~

$14.8 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets.

These increases were partially offset by:

$19.4 million decrease attributable to reduced natural gas basis spreads, increased fuel consumption, the impact of changes in contract mix, differences in gas quality, 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. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

Operating and Maintenance Expense — Operating and maintenance expense increased in ~~2008~~2010 compared to ~~2007,~~2009 primarily as a result of ~~the MEG, MPP~~our Michigan acquisition and ~~Southern Oklahoma acquisitions.~~

integration costs, turnaround activities at certain assets, repairs as a result of near record cold weather and efficiency projects.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in ~~2008~~2010 compared to ~~2007,~~2009 primarily as a result of our capital projects completed in 2009 and the ~~MEG, MPP and Southern Oklahoma acquisitions.~~

Michigan acquisition.

Other income —Other income relates to our reassessment of the fair value of contingent consideration for our acquisition of an additional 5% interest in Collbran from Delta Petroleum Company, or Delta, in February 2010.

Earnings from ~~Equity Method Investments~~Unconsolidated Affiliates — Earnings from ~~equity method investments decreased~~unconsolidated affiliates, representing our 40% ownership of Discovery, increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily due to ~~decreased equity earnings~~higher prices and increased NGL production, partially offset by differences in gas quality, 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 includes the impact of ~~$6.7 million~~organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption, differences in gas quality and turnarounds at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2010 compared to 2009, as a result of increased fee-based throughput volumes from our Michigan acquisition, and increased volumes at Discovery, partially offset by ~~increased equity earnings~~decreased volumes across certain assets. 2010 results include the impact of ~~$1.5 million from East Texas. Decreased equity earnings were primarily the~~volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of ~~the following variances, each representing 100% of the earnings drivers for~~near record cold weather at East Texas and ~~Discovery;~~


	•	Decreased equity earnings from Discovery were the result of a decrease in Discovery’s net income of $13.7 million due primarily to $32.5 million resulting from hurricanes Ike and Gustav, partially offset by $10.4 million higher product margins, $4.6 million lower depreciation and accretion expense and a 2008 reserve reversal of $3.5 million related to a recently approved Federal Energy Regulatory Commission rate case settlement.

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


	•	Increased equity earnings from East Texas were the result of an increase in East Texas’s net income of $6.0 million due primarily to a $14.9 million increase as a result of higher commodity prices, a $9.0 million increase due to increased fee-based revenue, and decreased general and administrative expenses of $2.9 million, partially offset by a $12.9 million decrease due to decreased NGL production, partially due to the effects of hurricanes and other severe weather and an increase in operating and maintenance expenses of $7.3 million.

~~Non-Controlling Interest in Income~~NGL Gross Production — Non-controlling interest in income reduced income by $3.9 million and $0.5 million in 2008 and 2007, respectively, and represents the non-controlling interest holders’ portion of the net income of our Collbran Valley Gas Gathering system joint venture, acquired in the MEG acquisition and in 2008 also includes the non-controlling interest holders’ portion of the net income of Jackson Pipeline Company, acquired in the MPP acquisition.

~~Natural gas transportedand/or~~ ~~processed~~NGL production increased in ~~2008~~2010 compared to ~~2007,~~2009, due primarily to increased volumes from ~~the MEG, MPP~~our Piceance Basin expansion project and ~~Southern Oklahoma acquisitions and~~ increased ~~volumes from East Texas, partially offset by decreased volumes from Pelico and Discovery. NGL production decreased in 2008 compared to 2007, due primarily to decreased~~ NGL production at ~~Discovery~~Discovery. 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 ~~hurricanes.~~

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

Year Ended December 31, ~~2007~~2009 vs. Year Ended December 31, ~~2006~~2008

Total Operating Revenues — Total operating revenues decreased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to the following:

$560.1 million decrease attributable to decreased commodity prices, which impact both sales and purchases, and includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged;

$138.3 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $183.2 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $44.9 million due to generally lower average prices of commodities in 2009; and


	•	$83.3 million decrease related to commodity derivative activity, an increase of $0.2 million which is included in sales of natural gas, NGLs and condensate, and a decrease of $83.5 million which is included in losses from derivative activity; offset by

	•	$49.0 million increase attributable to an increase in natural gas, NGL and condensate sales volumes, primarily as a result of the MEG and Southern Oklahoma acquisitions, partially offset by a decrease in natural gas sales volumes, primarily as a result of an amendment to a contract with an affiliate in 2006, which resulted in a prospective change in the reporting of certain Pelico revenues from a gross presentation to a net presentation;

	•	~~$17.2 million increase attributable to increased NGL and condensate prices; and~~

	•	~~$5.9 million increase in transportation, processing and other services revenue primarily attributable to an increase in natural gas throughput.~~

$62.1 million decrease due primarily to a decrease in natural gas sales volumes across certain assets, partially offset by increased revenues due to contractual amendments such that certain revenues changed from a net presentation to a gross presentation. These results include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project.

These decreases were partially offset by:

$8.2 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to the Michigan acquisitions, partially offset by decreased throughput volumes across other assets.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs ~~increased~~decreased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to ~~increased natural gas purchase volumes primarily as a result of the MEG~~decreased commodity prices, which impact both sales and ~~Southern Oklahoma acquisitions,~~purchases, partially offset by ~~decreased natural gas purchased volumes primarily as a result of an amendment to a contract with an affiliate in 2006,~~contractual amendments which resulted in a prospective change in ~~the reporting of~~ certain ~~Pelico~~ purchases from a ~~gross~~net presentation to a ~~net~~gross presentation.

Segment Gross Margin — Segment gross margin decreased in ~~2007~~2009 compared to ~~2006,~~2008, primarily as a result of the following:


	•	~~$83.3 million decrease related to commodity derivative activity;~~

	•	$2.5 million decrease attributable primarily to a decrease in marketing margins from the decline in the differences in natural gas prices at various receipt and delivery points across our Pelico system, which were atypically high in 2006; partially offset by

	•	$25.2 million increase primarily attributable to an increase in NGL and condensate production, partially as a result of the MEG and Southern Oklahoma acquisitions, and an increase in natural gas throughput volumes;

	•	~~$1.0 million increase primarily attributable to higher contractual fees charged to customers; and~~

	•	~~$0.5 million increase primarily attributable to favorable frac spreads.~~

79$138.3 million decrease related to commodity derivative activity, as discussed in the Operating Revenues section above;

$78.8 million decrease due to lower commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged; and

~~NGL production and~~$21.1 million decrease, primarily due to lower natural gas ~~transportedand/or~~ ~~processed during 2007 increased compared to 2006.~~volumes across certain assets. These ~~increases~~decreases include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project.

These decreases were ~~due primarily to increased volumes from Discovery, as well as an increase in volumes from the MEG and Southern Oklahoma acquisitions,~~ partially offset ~~by decreased~~by:

$16.7 million increase primarily as a result of increased fee-based throughput volumes ~~from Pelico.~~due to the Michigan acquisitions.

Operating and Maintenance Expense — Operating and maintenance expense ~~increased~~decreased in ~~2007~~2009 compared to ~~2006,~~2008, primarily as a result of ~~the MEG and Southern Oklahoma acquisitions, and higher labor and benefits and pipeline integrity costs.~~

our cost reduction initiatives, partially offset by increased expenses as a result of our Michigan acquisitions.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in ~~2007~~2009 compared to ~~2006,~~2008, primarily as a result of the ~~MEG~~Michigan acquisitions, and ~~Southern Oklahoma acquisitions.~~

our East Texas, Wyoming and Piceance Basin capital projects.

Earnings from ~~Equity Method Investments~~Unconsolidated Affiliates — Earnings from ~~equity method investments increased~~unconsolidated affiliates, representing our 40% ownership of Discovery, decreased in ~~2007~~2009 compared to ~~2006,~~2008. This decrease was as a result of a reduction in the recognition of Discovery’s deficit purchase price in 2009 compared to 2008. The reduction of deficit purchase price recognition was partially offset by increased earnings from Discovery. The increase in Discovery’s earnings are primarily ~~due to increased equity earnings of $7.2 million from Discovery and $2.6 million from East Texas. Increased equity earnings were primarily the~~as a result of the following variances ~~each~~in earnings drivers, representing 100% of ~~the earnings drivers for~~Discovery’s results of operations: Net income increased $2.5 million, or 7%, due primarily to $12.4 million higher gathering and transportation revenue, $13.2 million lower operating and maintenance expense and $2.6 million lower depreciation and accretion expense. These increases were largely offset by $18.5 million lower NGL sales margins resulting from sharply lower average per-unit margins on higher volumes of NGL equity sales and a $5.4 million unfavorable change in other income or expense, net. 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 decreased in 2009 compared to 2008 primarily as a result of decreased net income at East Texas, ~~and Discovery:~~


	•	~~Increased equity earnings from Discovery were the result of an increase in Discovery’s net income of $18.0 million, or 60%, due primarily to $39.0 million higher gross processing margins~~for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a third party owned pipeline rupture resulting from higher NGL sales volumes and NGL prices, partially offset by $9.9 million lower fee-based transportation, gathering, processing and fractionation revenues, $5.9 million higher operating and maintenance expense and $2.2 million higher other expenses. In addition, exceptionally strong commodity margins compelled Discovery’s customers to process their natural gas rather than by-pass, which led to higher product sales revenues on Discovery’s percent-of-proceeds and keep-whole processing contracts.

	•	Increased equity earnings from East Texas were the result of an increase in East Texas’s net income of $10.7 million, or 22%, due primarily to a $28.5 million increase as a result of higher commodity prices and a $1.1 million decrease in income tax expense due to recording a deferred tax liability of $1.8 million in 2006 related to the Texas margin tax; partially offset by an $11.6 million decrease due to a decline in natural gas volumes, a $3.0 million decrease due to decreased fee-based revenue, and an increase in operating and maintenance expenses of $2.8 million, primarily due to increased contract services, materials and supplies, and labor an benefits, increased depreciation expense of $1.2 million due to the addition of a new pipeline, and increased general and administrative expenses of $0.6 million, primarily due to higher allocated costs from DCP Midstream, LLC.

~~Non-Controlling Interest~~ in ~~Income~~a fire at East Texas.

Natural Gas Throughput — ~~Non-controlling interest~~Natural gas transported, processed and/or treated increased in ~~income reduced income~~2009 compared to 2008, due to increased fee-based throughput volumes from our Michigan acquisitions and increased volumes from the Tahiti project at Discovery, partially offset by ~~$0.5 million~~decreased volumes across certain assets. Results in ~~2007,~~both years include the impact of hurricanes and ~~represents~~operational downtime following the ~~non-controlling interest holders’ portion~~hurricanes. 2009 results include the impact of a third party owned pipeline rupture resulting in a fire at East Texas during the ~~net income~~first quarter.

NGL Gross Production — NGL production increased in 2009 compared to 2008, due primarily to increased NGL production from Discovery. Results in both periods include the impact of hurricanes and operational downtime and our ~~Collbran Valley Gas Gathering~~Wyoming system ~~joint venture, acquired~~pipeline integrity and enhancement project. 2009 results also include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas during the ~~MEG acquisition.~~

first quarter.
Results of Operations — Wholesale Propane Logistics Segment
This segment includes our propane transportation facilities, which includes one owned underground storage facility, six owned rail terminals, one ~~of which was idled in 2007 to consolidate our operations,~~owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals.

Variance
Variance

2008 vs. 2007 2007 vs. 2006
Year Ended December 31, Increase
Increase

2008 2007 2006 (Decrease) Percent (Decrease) Percent
(Millions, except operating data)

Operating revenues:
Sales of propane $ 482.1 $ 463.1 $ 375.0 $ 19.0 4 % $ 88.1 24 %
Transportation, processing and other 1.1 0.6 0.1 0.5 83 % 0.5 *
(Losses) gains from commodity derivative activity (0.2 ) (4.1 ) 0.1 (3.9 ) (95 )% (4.2 ) *

Total operating revenues 483.0 459.6 375.2 23.4 5 % 84.4 23 %
Purchases of propane 472.0 434.1 359.2 37.9 9 % 74.9 21 %

Segment gross margin(a) 11.0 25.5 16.0 (14.5 ) (57 )% 9.5 59 %
Operating and maintenance expense (9.9 ) (10.4 ) (8.6 ) (0.5 ) (5 )% 1.8 21 %
Depreciation and amortization expense (1.3 ) (1.1 ) (0.8 ) 0.2 18 % 0.3 38 %
Other 1.5 — — 1.5 * — — %

Segment net income $ 1.3 $ 14.0 $ 6.6 $ (12.7 ) (91 )% $ 7.4 *

Operating Data:
Propane sales volume (Bbls/d) 21,053 22,798 21,259 (1,745 ) (8 )% 1,539 7 %
   Year Ended December 31, Variance
2010 vs. 2009 Variance
2009 vs. 2008
   2010(a) 2009 2008 Increase
(Decrease) Percent Increase
(Decrease) Percent
   (Millions, except operating data)
Operating revenues:

Sales of propane
   $ 473.8    $ 347.2    $ 482.1    $ 126.6    36 % $ (134.9 ) (28 )%
Transportation, processing and other
   0.3    0.4    1.1    (0.1 ) (25 )% (0.7 ) (64 )%
(Losses) gains from commodity derivative activity
   (0.9 ) 0.6    (0.2 ) (1.5 ) *    0.8    *

Total operating revenues
   473.2    348.2    483.0    125.0    36 % (134.8 ) (28 )%
Purchases of propane
   444.3    299.3    472.0    145.0    48 % (172.7 ) (37 )%

Segment gross margin(b)
   28.9    48.9    11.0    (20.0 ) (41 )% 37.9    345 %
Operating and maintenance expense
   (12.6 ) (10.3 ) (9.9 ) 2.3    22 % 0.4    4 %
Depreciation and amortization expense
   (1.9 ) (1.4 ) (1.3 ) 0.5    36 % 0.1    8 %
Other income — affiliates
   3.0    —    1.5    3.0    100 % (1.5 ) (100 )%

Segment net income attributable to partners
   $ 17.4    $ 37.2    $ 1.3    $ (19.8 ) (53 )% $ 35.9    2,762 %

Operating Data:

Propane sales volume (Bbls/d)
   22,350    22,278    21,053    72    — % 1,225    6 %
  * Percentage change is not meaningful.
(a) Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition.
(b) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “How We Evaluate Our Operations” above.
Year Ended December 31, ~~2008~~2010 vs. Year Ended December 31, ~~2007~~2009
Total Operating Revenues — Total operating revenues increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily as a result of the following:
$111.7 million increase attributable to higher propane prices, which impact both sales and purchases; and
$35.4 million increase attributable to our acquisition of Atlantic Energy in July 2010.
This increase was partially offset by:
$20.5 million decrease attributable to a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather;
$1.5 million decrease due to ~~the following:~~commodity derivative activity.
• ~~$54.1 million increase attributable to higher propane prices;~~
• $3.9 million increase related to commodity derivative activity, which represents increased unrealized gains of $5.3 million, partially offset by increased realized cash settlement losses of $1.4 million; and
• ~~$0.5 million increase attributable to other fee revenue; partially offset by~~
• ~~$35.1 million decrease attributable to decreased propane sales volumes as a result of lower demand.~~
Purchases of Propane — Purchases of propane increased in ~~2008~~2010 compared to ~~2007, primarily due to increased~~2009 as a result of higher propane prices, which impact both sales and purchases, and our acquisition of Atlantic Energy in July 2010, partially offset by decreased ~~purchased~~propane sales volumes.
Segment Gross Margin — Segment gross margin decreased in ~~2008~~2010 compared to ~~2007, primarily~~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, partially offset by our acquisition of Atlantic Energy in July 2010. 2009 results reflect a late winter, increased ~~non-cash lower~~spot sales volumes and significantly higher per unit margins, approximately $6.0 million of ~~cost or market inventory adjustments of $15.1 million due~~which was attributable to ~~a decline in propane prices in the second half of 2008. We estimate that approximately half of the 2008 write downs were recovered through~~ the sale of inventory ~~in 2008. We also had lower per unit margins and lower propane sales volumes, partially offset by commodity derivative activity.~~
~~Propane sales volume decreased in 2008 compared to 2007, primarily as a result~~that was written down at the end of ~~lower demand.~~

81
~~Operating and Maintenance Expense~~ ~~— Operating and maintenance expense decreased in 2008 compared to 2007, primarily due to decreased property taxes.~~
~~Other~~ ~~— Other operating income increased due to a payment received in~~ the ~~second~~fourth quarter of ~~2008 from a supplier related to the early termination of its supply agreement.~~
2008.
~~Year Ended December 31, 2007 vs. Year Ended December 31, 2006~~
~~Total Operating Revenues~~ ~~— Total operating revenues increased in 2007 compared to 2006, primarily due to the following:~~
• ~~$60.8 million increase attributable to higher propane prices;~~
• $27.3 million increase attributable to higher propane sales volumes as a result of colder weather in the northeastern United States and the completion of the Midland terminal, which became operational in May 2007; and
• ~~$0.5 million increase in transportation, processing and other services; offset by~~
• ~~$4.2 million decrease related to commodity derivative activity.~~
~~Purchases of Propane~~ — Purchases of propane increased in 2007 compared to 2006, primarily due to increased prices and purchased volumes, primarily due to colder weather in the northeastern United States and increased purchased volumes due to the completion of the Midland terminal, which became operational in May 2007, partially offset by decreased non-cash lower of cost or market inventory adjustments recognized in 2007.
~~Segment Gross Margin~~ — Segment gross margin increased in 2007 compared to 2006, primarily as a result of higher per unit margins as a result of changes in contract mix and the ability to capture lower priced supply sources, decreased non-cash lower of cost or market inventory adjustments recognized in 2007, and higher sales volumes primarily due to the completion of the Midland terminal, which became operational in May 2007, partially offset by a decrease related to commodity derivative activity.
Propane sales volume increased in 2007 compared to 2006, due primarily to colder weather in the northeastern United States and the addition of the Midland terminal, which became operational in May 2007.
Operating and Maintenance Expense — Operating and maintenance expense increased in ~~2007~~2010 compared to ~~2006,~~2009, primarily as a result of our acquisition of Atlantic Energy.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.
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 were stable in 2010 compared to 2009. 2010 results reflect increased volumes due to our acquisition of Atlantic Energy, offset by 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 and increased spot sales volume.
Year Ended December 31, 2009 vs. Year Ended December 31, 2008
Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to ~~operating~~the following:
$163.8 million decrease attributable to lower propane prices, which impact both sales and purchases.
This decrease was partially offset by:
$28.9 million increase attributable to increased propane sales volumes; and
$0.8 million increase related to commodity derivative activity.
Purchases of Propane — Purchases of propane decreased in 2009 compared to 2008, due to lower propane prices, which impact both sales and purchases, partially offset by increased volumes.
Segment Gross Margin — Segment gross margin increased in 2009 compared to 2008, primarily as a result of increased volumes and per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.
Operating and Maintenance Expense — Operating and maintenance expense atincreased in 2009 compared to 2008 due to property taxes, partially offset by our cost reduction initiatives.
Other — Other operating income in 2008 related to payment received from a supplier regarding the ~~Midland terminal, which became operational~~early termination of its supply agreement.
Propane Sales Volume — Propane sales volumes increased 6% in ~~May 2007.~~

822009 compared to 2008.
Results of Operations — NGL Logistics Segment
This segment includes our Seabreeze, Wilbreeze and ~~Wilbreeze~~Wattenberg NGL and Black Lake transportation ~~pipelines and our 45% interest in Black Lake.~~

Variance
Variance

2008 vs. 2007 2007 vs. 2006
Year Ended December 31, Increase
Increase

2008 2007 2006 (Decrease) Percent (Decrease) Percent
(Millions, except operating data)

Operating revenues:
Sales of NGLs $ 5.4 $ 4.5 $ 1.1 $ 0.9 20 % $ 3.4 *
Transportation, processing and other 5.9 5.1 4.2 0.8 16 % 0.9 21 %

Total operating revenues 11.3 9.6 5.3 1.7 18 % 4.3 81 %
Purchases of NGLs 4.2 4.7 1.2 (0.5 ) (11 )% 3.5 *

Segment gross margin(a) 7.1 4.9 4.1 2.2 45 % 0.8 20 %
Operating and maintenance expense (1.0 ) (0.8 ) (1.6 ) 0.2 25 % (0.8 ) (50 )%
Depreciation and amortization expense (1.4 ) (1.4 ) (0.9 ) — — % 0.5 56 %
Earnings from equity method investment(b) 0.8 0.6 0.3 0.2 33 % 0.3 100 %

Segment net income $ 5.5 $ 3.3 $ 1.9 $ 2.2 67 % $ 1.4 74 %

Operating data:
NGL pipelines throughput (Bbls/d)(b) 31,407 28,961 25,040 2,446 8 % 3,921 16 %
pipelines:
   Year Ended December 31, Variance
2010 vs. 2009 Variance
2009 vs. 2008
   2010(a) 2009 2008 Increase
(Decrease) Percent Increase
(Decrease) Percent
   (Millions, except operating data)
Operating revenues:

Sales of NGLs
   $ 4.7    $ 3.0    $ 5.4    $ 1.7    57 % $ (2.4 ) (44 )%
Transportation, processing and other
   12.9    7.5    5.9    5.4    72 % 1.6    27 %

Total operating revenues
   17.6    10.5    11.3    7.1    68 % (0.8 ) (7 )%
Purchases of NGLs
   4.7    2.9    4.2    1.8    62 % (1.3 ) (31 )%

Segment gross margin(b)
   12.9    7.6    7.1    5.3    70 % 0.5    7 %
Operating and maintenance expense
   (3.7 ) (1.2 ) (1.0 ) 2.5    208 % 0.2    20 %
Depreciation and amortization expense
   (2.6 ) (1.4 ) (1.4 ) 1.2    86 % —    — %
Step acquisition — equity interest re-measurement gain
   9.1    —    —    9.1    100 % —    — %
Earnings from unconsolidated affiliates(c)
   0.8    1.9    0.8    (1.1 ) (58 )% 1.1    138 %

Segment net income attributable to partners
   $ 16.5    $ 6.9    $ 5.5    $ 9.6    139 % $ 1.4    25 %

Operating data:

NGL pipelines throughput
(Bbls/d)(c)
   38,282    30,160    31,407    8,122    27 % (1,247 ) (4 )%
(a) Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, 2010 the date of acquisition.
    * The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
~~Percentage change~~The impact to our results related to Marysville, acquired on December 30, 2010, is not ~~meaningful.~~significant.
~~(a)~~ (b) Segment gross margin consists of total operating revenues less purchases of ~~natural gas and~~ NGLs. Please read “How We Evaluate Our Operations” above.
~~(b)~~(c) ~~Includes~~For periods prior to July 30, 2010, includes our ~~proportionate~~50% share of the throughput volumes and earnings ~~of Black Lake for all periods presented. Earnings~~ for Black ~~Lake include~~Lake. Black Lake’s earnings included the ~~amortization~~accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.
Year Ended December 31, ~~2008~~2010 vs. Year Ended December 31, ~~2007~~2009
Total Operating Revenues — Total operating revenues increased in ~~2008~~2010 compared to ~~2007,~~2009, primarily ~~due to increased~~as a result of the Wattenberg pipeline acquisition, our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of decreased throughput volumes ~~increased transportation,~~resulting from ethane rejection and lower volumes at certain connected processing ~~and other revenue, and increases related to settlement of pipeline imbalances.~~
~~Purchases of NGLs~~ ~~— Purchases of NGLs decreased in 2008 compared to 2007, due to settlement of pipeline imbalances, partially offset by increased throughput volumes.~~
plants.
Segment Gross Margin — Segment gross margin increased in ~~2008~~2010 compared to ~~2007, primarily due to increases related to settlement~~2009, as a result of higher volumes from the Wattenberg pipeline ~~imbalances~~acquisition and our acquisition of an additional 50% interest in Black Lake, as well as higher per unit margins.
Operating and Maintenance Expense — Operating and maintenance expense increased ~~throughput volumes.~~
~~Overall, our NGL pipelines experienced an increase~~ in ~~throughput volumes in 2008 as~~2010 compared to ~~2007,~~2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an ~~increase~~additional 50% interest in ~~processing activity associated with~~Black Lake.
Depreciation and Amortization Expense— Depreciation and amortization expense increased ~~drilling due~~in 2010 compared to ~~higher commodity prices.~~
2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.
~~Earnings~~Step acquisition — equity interest re-measurement gain— Step acquisition — equity interest re-measurement gain results from ~~Equity Method Investments~~our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.
NGL Pipelines Throughput — ~~Earnings from equity method investments~~NGL pipelines throughput increased in ~~2008~~2010 compared to ~~2007, due to~~2009, as a result of increased ~~throughput~~ volumes ~~resulting~~from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in ~~higher~~ Black ~~Lake equity earnings.~~
Lake. 2009 results include the first quarter impact of ethane rejection and lower volumes at certain connected processing plants.
Year Ended December 31, ~~2007~~2009 vs. Year Ended December 31, ~~2006~~2008
Total Operating Revenues — Total operating revenues ~~increased~~decreased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to ~~changes in product mix and increased~~lower throughput volumes, as well as increased transportation, processing and other revenue. Increased volumes and transportation, processing and other revenue are primarily as a result of the addition of our Wilbreeze pipeline in December 2006.

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partially offset by higher per unit margins.
~~Purchases of NGLs~~ ~~— Purchases of NGLs increased in 2007 compared to 2006, primarily due to changes in product mix and increased volumes.~~
Segment Gross Margin — Segment gross margin increased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to ~~changes in product mix and increased volumes, as well as increased transportation, processing and other revenue.~~
~~Overall, our NGL pipelines experienced an increase in throughput volumes during 2007 as compared to 2006, primarily as a result of the addition of our Wilbreeze pipeline.~~
~~Operating and Maintenance Expense —~~~~Operating and maintenance expense decreased in 2007 compared to 2006, primarily due to lower pipeline integrity costs on our Seabreeze pipeline.~~
~~Depreciation and Amortization Expense~~ ~~— Depreciation and amortization expense increased in 2007 compared to 2006, primarily as a result of the addition of our Wilbreeze pipeline.~~
higher per unit margins.
Earnings from ~~Equity Method Investments~~Unconsolidated Affiliates — Earnings from ~~equity method investments~~unconsolidated affiliates increased in ~~2007~~2009 compared to ~~2006,~~2008, primarily due to ~~higher Black Lake revenues,~~decreased operating expenses.
NGL Pipelines Throughput — NGL pipeline throughput decreased in 2009 compared to 2008, due to declines at certain connected processing plants, partially offset by ~~increased project costs.~~
volumes from new interconnects.
Liquidity and Capital Resources
We expect our sources of liquidity to include:
cash generated from operations;
cash distributions from our unconsolidated affiliates;
• ~~cash generated from operations;~~
• ~~cash distributions from our equity method investments;~~
• ~~borrowings under our revolving credit facility;~~
• ~~cash realized from the liquidation of securities that are pledged under our term loan facility;~~
• ~~issuance of additional partnership units;~~
• ~~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.~~
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;
• ~~capital expenditures;~~
• ~~contributions to our equity method investments to finance our share of their capital expenditures;~~
• ~~business and asset acquisitions;~~
• collateral with counterparties to our swap contracts to secure potential exposure under these contracts, 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; and
• ~~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,~~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. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.
In 2010, we executed two public equity offerings which ~~may include~~generated net proceeds $189.3 million. The proceeds from the equity issuances were used primarily to fund our growth strategy, including acquisitions and organic expansion. The 2010 acquisitions included our purchase of the Wattenberg NGL pipeline, the Chesapeake marine terminal, an additional interest in our Black Lake NGL pipeline and the Marysville NGL storage facility for total cash consideration, net of cash acquired of $203.3 million. Our portion of expansion capital ~~spending.~~
~~Beginning~~expenditures for 2010 was $30.3 million. Additionally, we used the proceeds to fund our January 2011 $150.0 million acquisition of a 33.3% interest in ~~the third quarter~~Southeast Texas from DCP Midstream, LLC. The balance of ~~2008,~~ the capital markets experienced volatility, uncertainty and interventions by various governments around the globe. The effects of these market conditions include significant changes in the valuation of equity securities and overnight and longer-termrequirements were funded through borrowing ~~rates. The availability of~~on our revolving credit ~~through traditional sources of funding such as the commercial paper, bank lending and~~

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facility.
the private and public placement debt markets also decreased dramatically. In these market conditions, it is uncertain if we would be successful in obtaining timely additional funding from the traditional equity or debt markets if it were needed. Furthermore, the cost of such new funding could substantially exceed the cost of funds previously obtained. 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 ~~beyond that currently anticipated~~ could limit our borrowing capacity, raise our financing costs, as well as impact our compliance with ~~the Credit Agreement’s~~our financial covenant ~~requirements.~~
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 ~~significant~~ portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing ~~operations~~activities through ~~2013~~2015 with fixed price ~~natural gas~~commodity swaps and ~~crude oil swaps.~~collar arrangements. For additional information regarding our derivative activities, please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities.”
Our banking group is comprised of various financial institutions, of which certain institutions have recently merged. We do not expect the aggregate contractual financial commitment of these institutions to us to change during the remaining life of our existing credit agreement as a result of these mergers.
~~The capacity under our~~
Our Credit Agreement isconsists of a revolving credit facility with capacity of $850.0 million, which matures on June 21, 2012. As of December 31, 2010, the outstanding balance on the revolving credit facility was $398.0 million resulting in unused revolver capacity of $419.9 million, of which approximately ~~$824.6~~$265.0 million ~~net~~was available for general working capital purposes. Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman ~~Brothers’ unfunded commitment.~~ 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~~is currently 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 ~~our~~the Credit Agreement will not mature prior to the June 21, 2012 maturity date. As of February ~~23, 2009,~~25, 2011, we had approximately ~~$228.0~~$324.5 million of unused capacity under the Credit Agreement.
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 common units and debt securities.
In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net ~~available borrowings~~of offering costs, which we used to repay funds borrowed under the revolver portion of our Credit ~~Agreement.~~
~~Certain~~Facility.
In September 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received net proceeds, after deducting underwriting discounts and offering expenses, of $247.7 million, which we used to repay funds borrowed under the revolver portion of our ~~counterparties are experiencing financial difficulties,~~Credit Facility.
In November 2010, we issued 2,875,000 common units at $34.96 per unit. We received proceeds of $96.2 million, net of offering costs which ~~did not have a significant impact on our business in 2008.~~
we used to fund the Southeast Texas acquisition.
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 February ~~23, 2009,~~25, 2011, DCP Midstream, LLC had issued and outstanding parental guarantees totaling ~~$83.0~~$75.0 million toin favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. Prior to our initial public offering, DCP Midstream, LLC provided parental guarantees to certain counterparties to our commodity derivative instruments, totaling $43.0 million as of February 23, 2009. In July 2008, DCP Midstream, LLC provided additional parental guarantees to certain counterparties to our commodity derivative instruments, totaling $40.0 million as of February 23, 2009. We pay DCP Midstream, LLC a fee of ~~0.5%~~0.50% per annum on ~~$40.0~~$75.0 million of these guarantees. ~~The fee on the remaining guarantees is covered under the omnibus agreement with DCP Midstream, LLC.~~ As of February ~~23, 2009,~~25, 2011, we had a contingent issuance letter of credit facility for up to $10.0 million, on which we pay a fee of ~~$10.0 million.~~0.50% per annum. As of February 25, 2011, we had no letters of credit issued on this facility; 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 February ~~23, 2009,~~25, 2011, 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 certain commodity derivative instruments guaranteed by us or DCP Midstream, LLC are generally dependent on our or DCP Midstream, LLC’s credit ~~rating~~ratings and the thresholds ~~would~~could be reduced to $0 in the event ~~DCP Midstream, LLC’s~~that our individual credit ~~rating~~ratings were to fall below investment grade.

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Discovery is owned 40% by us and 60% by Williams Partners, LP. Discovery is managed by a two-member management committee, consisting of one representative from each owner. The members of the management committee have voting power corresponding to their respective ownership interests in Discovery. All actions and decisions relating to Discovery require the unanimous approval of the owners except for a few limited situations. Discovery must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of the distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.” Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of both owners in most instances.
East Texas is owned ~~25%~~50.1% by us and ~~75%~~49.9% by DCP Midstream, LLC. East Texas is managed by a four-member management committee, consisting of two representatives from each owner. The members of the management committee have voting power corresponding to their respective ownership interests in East Texas. ~~Most significant actions relating to East Texas require the unanimous approval of both owners.~~ East Texas must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of the distributions. Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of both owners except in certain situations, such as the breach or default of a material agreement or payment obligation, that are reasonably likely to have a material adverse effect on the business, operations or financial condition of East Texas.
Southeast Texas is owned 33.33% by us and 66.67% by two wholly-owned subsidiaries of DCP Midstream, LLC. Southeast Texas is managed by a three-member management committee, consisting of one representative appointed by us and two representatives from DCP Midstream, LLC. The members of the management committee have voting power corresponding to their respective ownership interests in Southeast Texas. Southeast Texas must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. In the event Southeast Texas has insufficient available cash for a quarterly distribution (including pursuant to our fee-based arrangement), DCP Midstream, LLC will assign its distribution rights, or contribute any distribution deficiency to Southeast Texas, the sole use of which shall be to pay the distribution deficiency owing to us related to our fee-based arrangement on storage and transportation gross margin, based on storage capacity and tailgate volumes. The management committee, by majority approval, will determine the amount of the distributions. Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of the owners except in certain situations, such as the breach or default of a material agreement or payment obligation, that are reasonably likely to have a material adverse effect on the business, operations or financial condition of Southeast Texas.
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, ~~along with~~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 December 31, 2008, we had $48.0 million in cash and cash equivalents. Of this balance, as of December 31, 2008, $21.2 million was held by Collbran Valley Gas Gathering, or Collbran, our 70% owned joint venture which we consolidate in our financial results. Other than the cash held by Collbran, this cash balance was available for general corporate purposes.
We had working capital of ~~$40.4~~$21.9 million as of December 31, ~~2008~~2010 and ~~a working capital deficit of $1.1~~$6.6 million as of December 31, ~~2007.~~2009. Included in these working capital amounts are net derivative working capital liabilities of $41.1 million and $34.2 million as of December 31, 2010 and December 31, 2009, respectively. The ~~changes~~change in working capital ~~are~~is primarily attributable to the factors described above. We expect that our future working capital requirements will ~~continue to~~ be impacted by these same factors.
As of December 31, 2010, we had $6.7 million in cash and cash equivalents. Of this balance, as of December 31, 2010, $0.8 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the ~~factors identified above.~~
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 derivative positions depending on the final regulations adopted by the United States Commodity Futures Trading Commission and the SEC.
Cash Flow —Operating, investing and financing activities was as follows:

Year Ended December 31,
2008 2007 2006
(Millions)

Net cash provided by operating activities $ 101.5 $ 65.4 $ 94.8
Net cash used in investing activities $ (166.9 ) $ (521.7 ) $ (93.8 )
Net cash provided by financing activities $ 88.9 $ 434.6 $ 3.0
   Year Ended December 31,
   2010 2009 2008
   (Millions)
Net cash provided by operating activities
   $ 140.8    $ 107.9    $ 177.6
Net cash used in investing activities
   $ (241.6 ) $ (163.8 ) $ (192.2 )
Net cash provided by (used in) financing activities
   $ 105.4    $ (3.9 ) $ 47.2
Our predecessor’s sources of liquidity, prior to ~~their~~its acquisition by us, included cash generated from operations and funding from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s bank accounts and all cash disbursements were made from these accounts. Cash transactions for our predecessor were handled by DCP Midstream, LLC and were reflected in partners’ equity as ~~intercompany~~net changes in parent advances to predecessors from DCP Midstream, LLC. ~~We maintain our own bank accounts, which are managed by DCP Midstream, LLC.~~

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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 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 $3.6 million for the year ended December 31, 2010, net of cash receipts of $6.2 million of which was associated with rebalancing our portfolio, and received cash for settlement of our commodity derivative instruments for the year ended
December 31, 2009 of $16.6 million, approximately $4.8 million of which was associated with rebalancing our portfolio. In addition, we received $3.6 million from DCP Midstream, LLC, related to the sale of surplus equipment as of December 31, 2010, which has been treated as an operating cash flow, because the title to the equipment was not transferred to DCP Midstream, LLC as of the balance sheet date.
We and our predecessors received cash distributions from ~~equity method investments~~unconsolidated affiliates of ~~$59.9~~$30.0 million, ~~$38.9~~$20.2 million and ~~$25.9~~$38.4 million during the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively. Distributions exceeded earnings by ~~$25.6~~$6.2 million, ~~for the year ended December 31, 2008. Earnings exceeded distributions by $0.4~~$1.7 million and ~~$3.3~~$20.2 million for the years ended December 31, ~~2007~~2010, 2009 and ~~2006,~~2008, respectively.
Net Cash Used in Investing Activities — Net cash used in investing activities during 2010 was comprised of: (1) acquisition expenditures of $203.3 million related to our acquisition of Atlantic Energy, the Wattenberg NGL pipeline, Marysville and an additional 55% interest in Black Lake; (2) capital expenditures of $50.7 million (our portion of which was $35.9 million and the noncontrolling interest holders’ portion was $14.8 million); and (3) investments in Discovery of $2.3 million; partially offset by (4) net proceeds from sale of available-for-sale securities of $10.1 million; (5) proceeds from sale of assets of $3.4 million; and (6) a return of investment from Discovery of $1.2 million.
Net cash used in investing activities during 2009 was primarily used for: (1) capital expenditures of $164.8 million (our portion of which was $79.7 million and the noncontrolling interest holders’ portion was $85.1 million), which primarily consisted of expenditures for installation of compression and expansion of our East Texas system, expansion of our Colorado system, and the completion of pipeline integrity system upgrades to our Wyoming system; (2) acquisition expenditure of $44.5 million, primarily related to the acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company of $45.1 million; and (3) investments in Discovery of $7.0 million, partially offset by (4) net proceeds from sale of available-for-sale securities of $50.0 million; (5) a return of investment from Discovery of $2.2 million; and (6) proceeds from sale of assets of $0.3 million.
Net cash used in investing activities during 2008 was primarily used for: (1) acquisition of MPP of $146.4 million; acquisition of the MEG subsidiaries of $10.9 million; (2) capital expenditures of ~~$41.0~~$72.7 million (our portion of which was $42.8 million and the noncontrolling interest holders’ portion was $29.9 million), which generally consisted of expenditures for construction and expansion of our infrastructure in addition to well connections and other upgrades to our existing facilities, including the pipeline integrity costs and system upgrades at ~~Douglas~~our Wyoming system; and (3) investments in ~~equity method investments~~unconsolidated affiliates of ~~$13.8 million; and (4) acquisition of the MEG subsidiaries of $10.9 million;~~$7.4 million, which were partially offset by ~~(5)~~(4) net proceeds from available-for-sale securities of $42.3 million; and ~~(6)~~(5) $2.9 million proceeds from the sale of assets.
Net cash used in investing activities during 2007 was primarily used for: (1) asset acquisitions of $191.3 million; (2) acquisition of equity method investments of $153.3 million; (3) acquisition of the MEG subsidiaries of $142.0 million; (4) capital expenditures of $21.3 million, which generally consisted of expenditures for construction and expansion of our infrastructure in addition to well connections and other upgrades to our existing facilities and (5) investments in equity method investments of $16.3 million; which were partially offset by; (6) net proceeds from available-for-sale securities of $2.4 million.
During 2007, we acquired Discovery, East Texas and the Swap from DCP Midstream, LLC for an initial cash outlay of approximately $243.7 million. The historical value of the assets acquired of approximately $153.3 million is reflected in “net cash used in investing activities.” The remaining $90.4 million is reflected in “net cash provided by financing activities.”
During 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC, for an initial cash outlay of approximately $67.4 million. The historical value of the assets acquired of approximately $56.7 million is reflected in “net cash used in investing activities.” The remaining $10.7 million is reflected in “net cash provided by financing activities” as the excess of the purchase price over the acquired assets.
We invested cash in equity method investments of $13.8 million, $16.3 million and $11.1 million during the years ended December 31, 2008, 2007 and 2006, respectively, of which $12.2 million, $6.9 million and $11.1 million, respectively, was to fund our share of capital expansion projects, $1.6 million in 2008 was to fund hurricane expenses and $9.4 million in 2007 was to fund working capital needs.
Net cash used in investing activities in 2006 was also used for capital expenditures, which generally consisted of expenditures for construction and expansion of our infrastructure in addition to well connections and other upgrades to our existing facilities.
Net Cash Provided By (Used in) Financing Activities —Net cash provided by financing activities during 2010 was comprised of: (1) borrowings of $868.2 million; (2) proceeds from the issuance of common units net of offering costs of $189.3 million; and (3) contributions from noncontrolling interests of $13.8 million; partially offset by (4) repayments of debt of $833.4 million; (5) distributions to our unitholders and general partner of $101.9 million; (6) distributions to noncontrolling interests of $25.6 million; (7) purchase of additional interest in a subsidiary of $3.5 million; (8) payment of deferred financing costs of $2.1 million; and (9) contributions from DCP Midstream, LLC of $0.6 million.
During 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 $300.5 million and did not exceed $722.4 million. The weighted-average indebtedness outstanding under the revolving credit facility was $622.5 million, $625.9 million, $634.7 million and $347.9 million for the first, second, third and fourth quarters of 2010, respectively.
We had unused revolver capacity, which is available commitments under the Credit Agreement of $209.3 million, $234.6 million, $486.5 million and $419.9 million at the end of the first, second, third and fourth quarters of 2010, respectively.
During 2010, we had the following net movements on our revolving credit facility:
$247.7 million repayment financed by the issue of $250.0 million of 3.25% Senior Notes due October 1, 2015;
$93.1 million repayment financed by the issue of 2,990,000 common units in August 2010; and
$96.2 million repayment financed by the issue of 2,875,000 common units in November 2010; partially offset by
$66.3 million borrowing to fund the acquisition of Atlantic Energy, which includes $17.3 million for propane inventory and working capital;
$16.3 million net borrowings for general corporate purposes;
$22.0 million borrowing to fund the acquisition of the Wattenberg pipeline;
$16.6 million borrowing to fund the acquisition of an additional 55% interest in Black Lake;
$100.8 million borrowing to fund the acquisition of Marysville, which includes $6.0 million for inventory and working capital; and
$10.0 million borrowing to fund repayment of our term loan facility.
During 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.
Net cash used in financing activities during 2009 was comprised of: (1) repayments of debt of $280.5 million; (2) distributions to our unitholders and general partner of $85.3 million; and (3) distributions to noncontrolling interests of $27.0 million, partially offset by (4) borrowings of $237.0 million; (5) contributions from non controlling interests of $78.7 million; (6) the issuance of common units for $69.5 million, net of offering costs; (7) net changes in advances to predecessor from DCP Midstream, LLC of $3.0 million; and (8) contributions from DCP Midstream, LLC of $0.7 million.
During 2009, 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 $608.3 million and did not exceed $656.8 million. The weighted average indebtedness outstanding was $656.7 million, $644.4 million, $638.3 million and $620.4 million for the first, second, third and fourth quarters of 2009, respectively.
We had liquidity, which is available commitments under the Credit Agreement of $239.3 million, $221.3 million, $221.3 million and $221.3 million at the end of the first, second, third and fourth quarters of 2009, respectively.
During 2009, we had the following net movements on our Credit Agreement:
$50.0 million borrowing under our revolving credit facility to fund a partial repayment of our term loan facility; partially offset by
$43.5 million repayment under our revolving credit facility.
Net cash provided by financing activities during 2008 was comprised ~~of;~~of: (1) proceeds from debt of $660.4 million; (2) the issuance of common units for $132.1 million, net of offering costs; (3) contributions from noncontrolling interests of $21.3 million; (4) contributions from DCP Midstream, LLC of $4.1 ~~million; and (4) net contributions from non-controlling interests of $2.4 million;~~million, partially offset by (5) repayment of debt of $633.9 million; ~~and~~ (6) distributions to our unitholders and general partner of $76.2 million; (7) distributions to noncontrolling interests of $46.4 million; and (8) net changes in advances from DCP Midstream, LLC relating to our predecessor of $14.2 million.
During 2008, total outstanding indebtedness under our ~~$824.6~~$850.0 million ~~credit agreement,~~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 $630.2 million and did not exceed $735.3 million. The weighted average indebtedness outstanding was $643.1 million, $690.0 million, $655.4 million and $666.6 million for the first, second, third and fourth quarters of 2008, respectively.
We had liquidity, which ~~includes~~is available commitments under the Credit Agreement, ~~and excludes cash on hand,~~ of $364.7 million, $385.4 million, $390.4 million and $228.0 million at the end of the first, second,

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third and fourth quarters of 2008, ~~respectively, which has been reduced by Lehman non-participation for all periods for comparative purposes.~~
respectively.
During 2008, we had the following ~~borrowings:~~
net movements on our Credit Agreement:
• $320.4 million borrowings for cash collateral postings with our commodity derivative contracts and for general working capital purposes. $293.9 million of these borrowings were repaid as of December 31, 2008;
• ~~$150.0~~
$146.4 million borrowing ~~on our term loan facility, the proceeds of which were used to reduce borrowings on our revolving credit facility; and~~
• ~~$190.0 million borrowing from our revolving credit facility, $146.4 million of which was used for the Michigan acquisition and the remainder was used for other capital expenditures.~~
Net cash provided by financing activities during 2007 was comprised of borrowings of $579.0 million, the issuance of common units for $228.5 million, net of offering costs, and contributions from non-controlling interests of $3.4 million, offset by repayment of debt of $217.0 million, the excess of purchase price over the acquired assets attributable to a payment related to our acquisition of Discovery, East Texas and the Swap of $90.4 million and of our wholesale propane logistics business of $9.9 million, distributions to our unitholders of $44.0 million, and net change in advances from DCP Midstream, LLC of $14.6 million.
~~During 2007, we had the following borrowings:~~
• ~~$11.0 million~~ under our revolving ~~credit facility to fund the purchase of the Laser assets from Midstream;~~
• ~~$89.0 million under our revolving credit facility to partially fund the Southern Oklahoma acquisition;~~
• ~~$88.0 million under a bridge loan to partially fund the Southern Oklahoma acquisition, which was extinguished with borrowings under our revolving credit facility;~~
• ~~$246.0 million from our revolving credit facility to finance the acquisition of our interests in East Texas and Discovery;~~
• ~~$100.0 million from our term loan facility and $35.0 million from our revolving credit facility to finance the MEG acquisition and for general corporate purposes; and~~
• ~~$10.0 million from our revolving credit facility for general corporate purposes, which was subsequently repaid.~~
~~Net cash provided by financing activities in 2006 was primarily comprised of borrowings on our~~ credit facility which wewas used ~~to fund~~for the ~~acquisition of our wholesale propane logistics business,~~Michigan acquisition; partially offset by ~~distributions to~~
$79.9 million repayment under our ~~unitholders, repayments of debt, changes in parent advances and the excess purchase price of~~revolving credit facility.
During 2008, we repaid $40.0 million under our ~~wholesale propane logistics business over its historical basis.~~
term loan facility
We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 1213 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
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,

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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.
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 ~~equity method investments.~~unconsolidated affiliates. We anticipate maintenance capital expenditures of between $10.0 tomillion and $15.0 million, and expenditures for expansion capital ~~expenditures~~ of ~~$65.0~~between $35.0 million and $50.0 million, for the year ending December 31, ~~2009. Maintenance capital includes an estimated $5.0~~2011 including $10.0 million ~~to complete the pipeline integrity and system upgrades to our Douglas system. DCP Midstream, LLC has agreed to reimburse us for our share of Discovery’s capital expenditures~~ for the ~~Tahiti pipeline lateral.~~expansion to storage capacity at our Southeast Texas system. The board of directors may approve additional growth capital during the year, at their discretion.
~~Our capital expenditures, excluding acquisitions, totaled $41.0 million and $21.3 million, including~~
The following table summarizes our maintenance ~~capital expenditures of $11.3 million and $2.4 million,~~ and expansion capital expenditures for our consolidated entities.
   Year Ended December 31, 2010    Year Ended December 31, 2009
   Maintenance
Capital
Expenditures    Expansion
Capital
Expenditures    Total
Consolidated
Capital
Expenditures    Maintenance
Capital
Expenditures    Expansion
Capital
Expenditures    Total
Consolidated
Capital
Expenditures
   (Millions)    (Millions)
Our portion
   $ 5.6       $ 30.3       $ 35.9       $ 12.6       $ 67.1       $ 79.7
Noncontrolling interest portion
   6.4       8.4       14.8       21.3       63.8       85.1

Total
   $ 12.0       $ 38.7       $ 50.7       $ 33.9       $ 130.9       $ 164.8

   Year Ended December 31, 2008
   Maintenance
Capital
Expenditures    Expansion
Capital
Expenditures    Total
Consolidated
Capital
Expenditures
   (Millions)
Our portion
   $ 13.6       $ 29.2       $ 42.8
Noncontrolling interest portion
   11.5       18.4       29.9

Total
   $ 25.1       $ 47.6       $ 72.7

In addition, we invested cash in unconsolidated affiliates of ~~$29.7~~$2.3 million, $7.0 million and ~~$18.9~~$7.4 million during 2008 and 2007, respectively. Maintenance capital in 2008 included $6.8 million associated with the pipeline integrity and system upgrades to our Douglas system. In conjunction with the acquisition of our investments in East Texas and Discovery, we entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for 25%, and will reimburse us for 40%, of certain capital expenditures as defined in the agreement, from July 1, 2007 through completion of the capital projects, for a period not to exceed three years. In the second quarter of 2006, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC made capital contributions to reimburse us for certain capital projects. We also have an agreement with certain producers whereby these producers will reimburse us for certain capital projects completed by us. As a result, during the year ended December 31, 2008, we had an increase in receivables of $0.3 million and during the year ended December 31, 2007, we had a decrease in receivables of $0.2 million related to collections of maintenance capital expenditures from DCP Midstream, LLC and producers. As a result, our total maintenance capital expenditures net of reimbursements were approximately $11.0 million and $2.6 million for the years ended December 31, 2010, 2009 and 2008, respectively, of which $2.3 million, $2.8 million and ~~2007, respectively.~~
~~During the third quarter of 2008, we announced that Collbran Valley Gas Gathering, LLC, or Collbran, plans~~$5.8 million, respectively, was to ~~invest approximately $150.0 million over a multi-year period to construct approximately 20 miles of24-inch~~ diameter gathering pipeline, and compression and liquids handling facilities, to support its Colorado system, located in the Collbran Valley area of the Piceance Basin in western Colorado. We are the operator and 70% owner of Collbran. We ultimately expect to invest approximately $105.0 million in this project, which is in proportion tofund our ~~ownership interest. The gathering system is designed to ultimately have throughput capacity of over 600 million cubic feet per day, orMMcf/d,~~ ~~and is supported by long-term acreage dedications. Our~~ share of ~~the Collbran investment was approximately $5.6 million in 2008~~capital expansion projects, and ~~we will invest approximately $57.0~~$4.2 million in 2009, was to ~~achieve throughput capacity of approximately200 MMcf/d~~fund repairs to Discovery following damage caused by hurricane Ike in ~~the third quarter of 2009. Our share~~2008 (of which $1.2 and $2.2 million was returned to us by Discovery during 2010 and 2009, respectively).
Capital expenditures decreased in 2010 compared to 2009 as a result of the ~~remaining investment~~substantial completion during 2009 of our expansion projects in ~~primarily compression equipment of approximately $42.4 million may be spent in 2010~~our Colorado and ~~beyond as production volumes increase, providing total throughput capacity in excess of600 MMcf/d.~~
~~During the third quarter of 2008, we announced plans, along with DCP Midstream, LLC, to invest approximately $56.0 million in~~ East Texas to construct a gathering pipeline to support the East Texas system. Our interest in this pipeline is currently 25%. Our net investment is approximately $14.0 million. Of that total, we spent approximately $1.3 million in 2008 and expect to spend the remaining $12.7 million in 2009. The pipeline is scheduled to be operational during the second quarter of 2009.
During the third quarter of 2008, we announced plans to pursue development of a natural gas pipeline in the Haynesville shale in northern Louisiana. Development of a potential pipeline project is highly dependent upon drilling and development plans in the area, securing appropriate levels of shipper contractual commitments and securing financing. We spent approximately $2.3 million in 2008 on this project.
systems.
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 ~~other~~ debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

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We expect to fund future capital expenditures with ~~restricted investments,~~ funds generated from our operations, borrowings under our credit facility, issuance of long-term debt and the issuance of additional partnership units. If these sources are not sufficient, we ~~may~~will reduce our ~~capital~~discretionary spending.
~~Given our long-term strategy of profitable growth, our long-term objective is to obtain an investment grade credit rating, to increase our available sources to fund capital expenditures.~~
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, including payment to our general partner related to our incentive distribution rights, of $101.9 million, $85.3 million and $76.2 million during 2010, 2009 and ~~$44.0 million during~~ 2008, ~~and 2007,~~ respectively. 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— ~~On June 21, 2007, we entered into an Amended and Restated Credit Agreement, or the Credit Agreement, which amended our existing Credit Agreement. This new5-year~~The Credit Agreement consists of ~~a $764.6~~an $850.0 million revolving credit ~~facility and a $60.0 million term loan facility, and~~at December 31, 2010. The Credit Agreement matures on June 21, 2012. ~~The amendment also improved pricing and certain other terms and conditions of the Credit Agreement.~~ As of December 31, ~~2008,~~2010, the outstanding balance on the revolving credit facility was ~~$596.5~~$398.0 million ~~and the outstanding balance on the~~resulting in unused revolver capacity of $419.9 million, of which approximately $265.0 million was available for general working capital purposes. The term loan ~~facility~~ was ~~$60.0 million.~~
repaid during the first quarter of 2010.
Our obligations under the revolving credit facility are ~~unsecured, and the~~unsecured. The term loan facility, iswhich was repaid during the first quarter of 2010, was secured at all times by high-grade securities, which ~~are~~we classified as restricted investments in the accompanying 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 December 31, ~~2008~~2010 and ~~2007, there were~~2009, we had outstanding letters of credit issued under the Credit Agreement of $32.1 million and $0.3 million, ~~and $0.2 million,~~ respectively.
We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of London Interbank Offered Rate, or LIBOR, borrowings. Indebtedness under the revolving credit facility bears interest at either: (1) the higher of ~~Wachovia~~Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%; or (2)��LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our ~~leverage level or~~ credit rating. As of December 31, ~~2008,~~2010, the weighted-average interest rate on our revolving credit facility was ~~2.08%~~1.14% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our ~~applicable leverage level or debt~~credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to either: (1) LIBOR plus 0.10%; or (2) the higher of ~~Wachovia~~Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%. ~~As of December 31, 2008, the interest rate on our term loan facility was 1.54%.~~
~~The Credit Agreement prohibits us from making distributions of Available Cash to unitholders if any default or event of default (as defined in the Credit Agreement) exists.~~
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. ~~The Credit Agreement also requires us to maintain an interest coverage ratio (the ratio~~
Description of ~~our consolidated EBITDA to our consolidated interest~~Debt Securities
On September 30, 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received net proceeds of $247.7 million, net of underwriters’ fees, related expense ~~in each case as is defined by the Credit Agreement)~~and unamortized discounts of ~~equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination.~~

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~~Bridge Loan~~
~~In May 2007, we entered into a two-month bridge loan, or the Bridge Loan, which provided for borrowings up to $100.0~~$1.5 million, $0.6 million and ~~had terms and conditions substantially similar~~$0.2 million, respectively which we used to ~~those~~repay funds borrowed under the revolver portion of our Credit ~~Agreement. In conjunction~~Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.
We incurred $2.1 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our consolidated balance sheets. We will amortize these costs over the term of the notes.
The notes are senior unsecured obligations, ranking equally in right of payment with our ~~entering into the Bridge Loan,~~existing unsecured indebtedness, including indebtedness under our Credit ~~Agreement was amended~~Facility. We are not required to ~~provide for additional unsecured indebtedness, of an amount not~~make mandatory redemption or sinking fund payments with respect to ~~exceed $100.0 million, which was due and payable no later than August 9, 2007.~~
~~We used borrowings on the Bridge Loan of $88.0 million to partially fund the Southern Oklahoma acquisition.~~these notes. The ~~remaining $12.0 million available for borrowing on the Bridge Loan was not utilized. We used~~securities are redeemable at a ~~portion of the net proceeds of the private placement to extinguish the $88.0 million outstanding on the Bridge Loan in June 2007.~~
premium at our option.
Total Contractual Cash Obligations and Off-Balance Sheet Obligations
A summary of our total contractual cash obligations as of December 31, ~~2008,~~2010, is as follows:

Payments Due by Period
2014 and

Total 2009 2010-2011 2012-2013 Thereafter
(Millions)

Long-term debt(a) $ 733.4 $ 26.6 $ 42.4 $ 664.4 $ —
Operating lease obligations 44.7 12.4 16.9 12.8 2.6
Purchase obligations(b) 632.8 140.8 201.9 188.2 101.9
Other long-term liabilities(c) 8.5 — 0.4 0.1 8.0

Total $ 1,419.4 $ 179.8 $ 261.6 $ 865.5 $ 112.5

   Payments Due by Period
   Total    2011    2012-2013    2014-2015    2016 and
Thereafter
   (Millions)
Long-term debt(a)
   $ 735.1       $ 33.2       $ 432.8       $ 269.1       $ —
Operating lease obligations(b)
   43.8       15.8       22.1       4.7       1.2
Purchase obligations(c)
   614.0       324.0       176.0       65.4       48.6
Other long-term liabilities(d)
   12.1       —       0.5       0.3       11.3

Total
   $ 1,405.0       $ 373.0       $ 631.4       $ 339.5       $ 61.1

(a) Includes interest payments on long-term debt that has been hedged ~~because the~~and on debt securities that have been issued. These interest ~~rate is determinable.~~payments are $33.2 million, $34.8 million and $19.1 million for 2011, 2012-2013 and 2014-2015, respectively. Interest payments on long-term debt ~~which~~that has not been hedged are not included as ~~they~~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 contractual 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) ~~Purchase~~Our purchase obligations are contractual obligations and include ~~$3.3~~$3.8 million of purchase orders for capital expenditures and ~~$629.5~~$610.2 million of various non-cancelable commitments to purchase physical quantities of ~~commodities in future periods.~~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 December 31, ~~2008.~~2010. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.
~~(c)~~ (d) Other long-term liabilities include ~~$7.9~~$10.8 million of asset retirement obligations and ~~$0.6~~$1.3 million of environmental reserves recognized onin the consolidated balance ~~sheet.~~sheet at December 31, 2010.
We have no items that are classified as off balance sheet obligations.
Critical Accounting Policies and Estimates
Our ~~off-balance arrangements consist solely~~financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our ~~operating lease obligations.~~
accounting policies that currently affect our financial condition and results of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Description
Judgments and Uncertainties
Effect if Actual Results Differ
from Assumptions
Inventories
Inventories, which consist of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory. If the market value of our inventory is lower than the cost, we may be exposed to losses that could be material. If commodity prices were to decrease by 10% below our December 31, 2010 weighted-average cost, our net income would be affected by approximately $6.5 million.
Impairment of Goodwill
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. We completed our impairment testing of goodwill using the methodology described herein, and determined there was no impairment. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices and throughput volumes. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. We have not recorded any impairment charges on goodwill during the year ended December 31, 2010. The carrying value of goodwill as of December 31, 2010 by reporting unit was $52.8 million for our Colorado system, $36.9 million for our Wholesale Propane Logistics business and $10.0 million for our Michigan system, totaling $99.7 million.
Description
Judgments and Uncertainties
Effect if Actual Results Differ
from Assumptions
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Our impairment analyses may require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. These techniques are also used when allocating the purchase price to acquired assets and liabilities. Using the impairment review methodology described herein, we have not recorded any impairment charges on long-lived assets during the year ended December 31, 2010. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. The carrying value of our long-lived assets as of December 31, 2010 was $1,256.1 million.
Impairment of Investments in Unconsolidated Affiliates
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. Our impairment loss calculations require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Using the impairment review methodology described herein, we have not recorded any impairment charges on investments in unconsolidated affiliates during the year ended December 31, 2010. If the estimated fair value of our unconsolidated affiliates is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value. The carrying value of our unconsolidated affiliates as of December 31, 2010 was $104.3 million.
Description
Judgments and Uncertainties
Effect if Actual Results Differ
from Assumptions
Accounting for Risk Management Activities and Financial Instruments
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and the expected relationship with quoted market prices. If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2010 would have affected net income by approximately $7.2 million for the year ended December 31, 2010.
Accounting for Equity-Based Compensation
Our long-term incentive plan permits for the grant of restricted units, phantom units, unit options and substitute awards. Equity-based compensation expense is recognized over the vesting period or service period of the related awards. We estimate the fair value of each award, and the number of awards that will ultimately vest, at the end of each period. Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period. If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in compensation expense.
Accounting for Asset Retirement Obligations
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled. Estimating the fair value of asset retirement obligations requires management to apply judgment to evaluate the necessary retirement activities, estimate the costs to perform those activities, including the timing and duration of potential future retirement activities, and estimate the risk free interest rate. When making these assumptions, we consider a number of factors, including historical retirement costs, the location and complexity of the asset and general economic conditions. If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in our asset retirement obligations. Establishing an asset retirement obligation has no initial impact on net income. A 10% change in depreciation and accretion expense associated with our asset retirement obligations during the year ended December 31, 2010 would impact our net income by approximately $0.1 million.
Recent Accounting Pronouncements
~~Statement of Financial Accounting Standards, or SFAS, No. 162 “The Hierarchy of Generally Accepted Accounting Principles,”~~~~or SFAS 162~~ ~~— In May 2008, the~~ Financial Accounting Standards Board, or FASB, ~~issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework,~~Accounting Standards Update, or ~~hierarchy,~~ASU, 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for ~~selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. SFAS 162 is effective 60 days following~~

91

the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We have assessed the impact of the adoption of SFAS 162, and believe that there will be no impact on our consolidated results of operations, cash flows Business Combinations”,or ~~financial position.~~

~~FASB Staff Position, or FSP,No. SFAS 142-3~~ ~~“Determination of the Useful Life of Intangible Assets,”~~or~~FSP 142-3~~ASU 2010-29 — In ~~April 2008,~~December 2010, the FASB issued~~FSP 142-3,~~ ASU 2010-29 which ~~amends~~amended Accounting Standards Codification, or ASC, Topic 805 “Business Combinations” to specify that if a public entity presents comparative financial statements, the ~~factors~~entity should disclose revenue and earnings of the combined entity as though the business combination that ~~should be considered~~occurred during the year had occurred as of the beginning of the comparable prior annual reporting period only. The ASU also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and the amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in ~~developing renewal or extension assumptions used to determine~~ the ~~useful life of a recognized intangible.FSP 142-3~~reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after January 1, 2011 and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.

ASU 2010-28 “Intangibles — Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for ~~fiscal years~~Reporting Units with Zero or Negative Carrying Amounts”,or ASU 2010-28 — In December 2010, the FASB issued ASU 2010-28 which amended ASC Topic 350 “Goodwill and Other”. ASU 2010-28 requires an entity with reporting units that have carrying amounts that are zero or negative to assess whether it is more likely than not that the reporting units’ goodwill is impaired. If the entity determines that it is more likely than not that the goodwill of one or more of its reporting units is impaired, the entity is required to perform Step 2 of the goodwill impairment test for those reporting unit(s) and record any resulting impairment as a cumulative-effect adjustment to beginning retained earnings. The provisions of ASU 2010-28 became effective for us on January 1, 2011, and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.

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 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 ~~15, 2008,~~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 ~~interim periods within those fiscal years. We are~~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 consolidated financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements”,or ASU 2009-13 — In October 2009, the ~~process of assessing~~FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the ~~impact ofFSP 142-3~~ ~~but do not expect~~accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a ~~material~~combined unit. ASU 2009-13 became effective for us on January 1, 2011 and there was no impact on our consolidated results of operations, cash flows and financial position as a result of adoption.

~~SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133~~~~,” or SFAS 161~~ — In March 2008, the FASB issued SFAS 161, which requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our disclosures, and will make the required disclosures in our March 31, 2009 consolidated financial statements.

~~SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51~~~~,” or SFAS 160 —~~In December 2007, the FASB issued SFAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 was effective for us on January 1, 2009, and did not have a significant impact on our consolidated results of operations, cash flows or financial position. As a result of adoption effective January 1, 2009, we will reclassify our non- controlling interests in the consolidated balance sheets to partners’ equity.

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

~~SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115~~~~,” or SFAS 159~~ — In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. The provisions of SFAS 159 became effective for us on January 1, 2008. We have not elected the fair value option relative to any of our financial assets and liabilities which are not otherwise required to be measured at fair value by other accounting standards. Therefore, there is no effect of adoption reflected in our consolidated results of operations, cash flows or financial position.

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


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

	•	~~establishes a framework for measuring fair value;~~

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

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

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

Upon the adoption of this standard we incorporated the marketplace participant view as prescribed by SFAS 157. Such changes included, but were not limited to, changes in valuation policies to reflect an exit price methodology, the effect of considering our own non-performance risk on the valuation of liabilities, and the effect of any change in our credit rating or standing. As a result of adopting SFAS 157, we recorded a transition adjustment of approximately $5.8 million as an increase to earnings and approximately $1.3 million as an increase to AOCI during the three months ended March 31, 2008. All changes in our valuation methodology have been incorporated into our fair value calculations subsequent to adoption.

~~Pursuant to FASB Staff Position157-2,~~ the FASB issued a partial deferral, ending on December 31, 2008, of the implementation of SFAS 157 as it relates to all non-financial assets and liabilities where fair value is the required measurement attribute by other accounting standards. While we have adopted SFAS 157 for all financial assets and liabilities effective January 1, 2008, we are in the process of assessing the impact SFAS 157 will have on our non-financial assets and liabilities, but do not expect a material impact on our consolidated results of operations, cash flows or financial positions upon adoption.

~~FSPNo. 157-3~~ ~~“Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,”~~or~~FSP 157-3~~ ~~— In October 2008, the FASB issuedFSP 157-3,~~ which provides guidance in situations where a) observable inputs do not exist, b) observable inputs exist but only in an inactive market and c) how market quotes should be considered when assessing the relevance of observable and unobservable inputs to determine fair value.~~FSP 157-3~~ was effective upon issuance, including prior periods for which financial statements have not been issued. We believe that the financial assets that are reflected in our financial statements are transacted within active markets, and therefore no adjustment to our fair value methodology was required and there is no effect on our consolidated results of operations, cash flows or financial positions as a result of the adoption of this FSP.

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

issuance of shares should be accounted for and d) how to account for a change in an investment from the equity method to the cost method. This issue is effective for us on January 1, 2009, and although we do not expect any changes to the manner in which we apply equity method accounting, this guidance will be considered on a prospective basis to transactions with equity method investees.

~~EITF 07-04~~ ~~“Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”~~or~~EITF 07-04 —In March 2008, the EITF issued ETIF07-04.~~ This issue seeks to improve the comparability of earnings per unit, or EPU, calculations for master limited partnerships with incentive distribution rights in accordance with FASB Statement No. 128 and its related interpretations. This issue is effective for us on January 1, 2009 and will be incorporated into our EPU calculations beginning with the quarter ending March 31, 2009. We are in the process of assessing the impact of~~EITF 07-04~~ ~~on our EPU calculations, and will make any required changes to our calculation methodology for the quarter ending March 31, 2009.~~


Item 7A.	*Quantitative and Qualitative Disclosures about Market Risk*

Market risk is the risk of loss arising from adverse change in market prices and rates. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate a portion of the effects of identified risks. In general, we

attempt to mitigate a portion of the risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements.

Risk Management Policy

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. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. ~~Prior to the formation of the~~

See Note 12, Risk Management ~~Committee, we were utilizing DCP Midstream, LLC’s risk management policies~~ and ~~procedures and risk management committee to monitor and manage market risks.~~

~~See Note 2, Accounting for Risk Management~~Hedging Activities, ~~and Financial Instruments,~~ of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the accounting for derivative contracts.

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~~

At December 31, 2010, we had interest rate swap agreements totaling $450.0 million, of which we have ~~been~~ designated $275.0 million as cash flow hedges and ~~effectiveness is determined by matching~~account for the ~~principal balance~~remaining $175.0 million under the mark-to-market method of accounting. As we expect to have variable rate debt levels equal to or exceeding our swap positions during their term, the entire $450.0 million of these agreements mitigate our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014. Based on our current operations we believe our interest rate swap agreements adequately mitigate our interest rate risk associated with our variable rate debt. As of February 25, 2011, we had interest rate swap agreements totaling $450.0 million, of which we have designated $425.0 million as cash flow hedges and ~~terms with that~~account for the remaining $25.0 million under the mark-to-market method of ~~the specified obligation.~~ accounting.

At December 31, ~~2008,~~2009, we had interest rate swap agreements totaling $575.0 million, all of which we had designated as cash flow hedges. In conjunction with the issuance of $250.0 million of 3.25% Senior Notes, we paid down our revolving credit facility, discontinued hedge accounting on $225.0 million of our existing swap agreements, terminated certain swap agreements for $1.3 million, and modified certain swap agreements to reduce the total outstanding amount by $125.0 million. Additionally, the term on $150.0 million of the swap agreements was extended through June 2014. This resulted in $450.0 million of these swap agreements mitigating our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014.

At December 31, 2010, the effective weighted-average interest rate on our ~~$596.5 million of~~ outstanding ~~revolver~~ debt was ~~4.48%~~4.42%, taking into account ~~the $575.0 million of indebtedness with designated~~our interest rate ~~swaps.~~

swap agreements totaling $450.0 million.
Based on the annualized unhedged borrowings under our credit facility of ~~$81.5~~$123.0 million as of December 31, ~~2008,~~2010, a 0.5% movement in the base rate or LIBOR rate would result in an approximately ~~$0.4~~$0.6 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 ~~sales~~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~~swaps and ~~crude oil contracts~~collar arrangements 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 ~~weakening~~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 ~~correlation~~relationship between NGL prices and crude oil prices, with some recent exceptions and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps and costless collars to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship. As a result of these transactions, we have mitigated a ~~significant~~ portion of our expected natural gas, NGL and condensate commodity price risk through ~~2013.~~

2015.
The derivative financial instruments we have entered into are typically referred to as “swap” ~~contracts.~~contracts and “collar” arrangements. These swap contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.

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

We also use commodity collar arrangements which include the combination of a sold call and a purchased put. The sold call establishes the maximum prices that we will receive for contracted commodity volumes, and the purchased put establishes the minimum price that we will receive.
The following ~~table sets~~tables set forth additional information about our fixed price ~~natural gas~~commodity swaps and ~~crude oil swaps~~collar arrangements 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:~~
operations, as of February 25, 2011:
Commodity Swaps
Period
Commodity Notional
Volume
Reference Price
Price Range
~~Swap~~
~~Period~~
~~Commodity~~ ~~Notional Volume~~ ~~Reference Price~~ ~~Price Range~~
January ~~2009~~2011 — December ~~2009~~2014
Natural Gas ~~2,000~~500 MMBtu/d
IFERC Monthly Index Price for Colorado Interstate
Gas Pipeline(a)
$5.06/MMBtu
January 2011 — December 2014
Natural Gas 500 MMBtu/d Texas Gas Transmission ~~Price(a)~~Price(b) $~~9.20/~~4.87/MMBtu
~~January 2010~~
March 2011 — December ~~2010~~2011
Natural Gas ~~1,900 MMBtu/d~~ ~~Texas Gas Transmission Price(a)~~ ~~$9.20/MMBtu~~
~~January 2009 — December 2013~~ ~~Natural Gas~~ ~~1,500 MMBtu/d~~ ~~NYMEX Final Settlement Price(b)~~ ~~$8.22/MMBtu~~
~~January 2009 — December 2013~~ ~~Natural Gas Basis~~ ~~1,500 MMBtu/~~400MMBtu/d IFERC Monthly Index Price for ~~NYMEX less~~
~~Panhandle Eastern Pipe Line(c)~~ Houston Ship Channel(d) $~~0.68/~~4.21/MMBtu
January ~~2009~~2011 — December ~~2009~~2011
Crude Oil ~~2,450~~2,600 Bbls/d Asian-pricing of NYMEX
crude oil ~~futures(d)~~futures(c) $~~63.05~~56.75 - ~~$86.95/~~$83.80/Bbl
~~January 2010 — December 2010~~ ~~Crude Oil~~ ~~2,415 Bbls/d~~ ~~Asian-pricing of NYMEX crude oil futures(d)~~ ~~$63.05 - $87.25/Bbl~~
~~January 2011 — December 2011~~ ~~Crude Oil~~ ~~2,350 Bbls/d~~ ~~Asian-pricing of NYMEX crude oil futures(d)~~ ~~$66.72 - $87.25/Bbl~~
January 2012 — December 2012
Crude Oil 2,325 Bbls/d Asian-pricing of NYMEX
crude oil ~~futures(d)~~futures(c) $66.72 - ~~$90.00/~~$99.85/Bbl
January 2013 — December 2013
Crude Oil ~~1,250~~2,250 Bbls/d Asian-pricing of NYMEX
crude oil ~~futures(d)~~futures(c) $67.60 - ~~$71.20/~~$99.85/Bbl
~~March 2009~~
January 2014 — December ~~2010(f)~~
~~Natural Gas~~ ~~1,634 MMBtu/d~~ ~~IFERC Monthly Index Price for~~
~~Colorado Interstate Gas Pipeline(e)~~ ~~$3.94/MMBtu~~
~~April 2010 — December 2011(f)~~2014
Crude Oil ~~250~~1,500 Bbls/d Asian-pricing of ~~NYMBEX~~ NYMEX
crude oil ~~futures(d)~~futures(c) $~~56.75~~74.90 - ~~$59.30/~~$96.08/Bbl
January 2015 — December 2015
Crude Oil 1,000 Bbls/d Asian-pricing of NYMEX
crude oil futures(c) $92.00 - $100.04/Bbl
April 2011 — December 2011
NGLS 405 Bbls/d Mt. Belvieu Non-TET(e) $0.55 - $2.38/Gal
(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.
~~(b)~~ ~~NYMEX final settlement price for natural gas futures contracts (NG).~~
(c) ~~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.~~
~~(d)~~ Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).
~~(e)~~ (d) The Inside FERC monthly published index price for natural gas delivered into the ~~Colorado Interstate Gas (CIG) pipeline.~~Houston Ship Channel area.
(e) The average monthly OPIS price for Mt. Belvieu Non-TET.
Commodity Collar Arrangements
Period
Commodity Notional
Volume
Reference Price
Collar
Price Range
~~(f)~~
January 2011 — December 2012
~~These trades were entered into subsequent to December 31, 2008.~~Crude Oil 200 Bbls/d(a) Asian-pricing of NYMEX crude oil futures(b) $80.00 - $97.40/Bbl
(a) Reflects separate purchased put and sold call contracts, resulting in a collar arrangement.
(b) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).
At December 31, ~~2008,~~2010, the aggregate fair value of the fixed price ~~natural gas~~commodity swaps and ~~crude oil swaps~~collar arrangements described above was a net ~~gain~~loss of ~~$6.5 million and $13.5 million respectively.~~
$62.6 million.
Our annual sensitivities for 2011 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 ~~significant~~ portion of our commodity price exposure for ~~propane~~NGLs, and heavier NGLs. Due to current movements in the relationship of NGL prices to crude oil prices outside of recent historical ranges, we have provided an additional sensitivity factor to capture movements up or down in this relationship. We have combined the NGL and crude oil sensitivities into one factor, and addedshow 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. Given our current contract mix and the commodity derivative contracts we have in place, we have updated our annualized sensitivities for 2009 as shown in the table below, which excludes the impact from mark-to-market on our commodity derivatives.

Commodity Sensitivities Excluding Non-Cash Mark-To-Market

Estimated

Decrease in

Annual Net

Per Unit Decrease Unit of Measurement Income
(Millions)

Natural gas prices $ 1.00 MMBtu $ 0.3
Crude oil prices(a) $ 5.00 Barrel $ 1.7
NGL to crude oil price relationship(b) 5 percentage
point change Barrel $ 4.6

96
   Per Unit Decrease    Unit of
Measurement    Estimated
Decrease in
Annual Net
Income
Attributable
to Partners
         (Millions)
Natural gas prices
   $ 1.00       MMBtu    $ 0.4
Crude oil prices(a)
   $ 5.00       Barrel    $ 2.5
NGL to crude oil price relationship(b)

5 percentage point
change
      Barrel    $ 7.7
(a) Assuming 60% NGL to crude oil price relationship.
(b) Assuming 60% NGL to crude oil price relationship and ~~$60.00/~~$80.00/Bbl crude oil price. Generally, this sensitivity changes by ~~$1.5~~$1.9 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from ~~$60.00/~~$80.00/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 ~~$60.00/~~$80.00/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 ~~2009~~2011 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

Estimated

Mark-to-Market

Impact

(Decrease in

Per Unit Increase Unit of Measurement Net Income)
(Millions)

Natural gas prices $ 1.00 MMBtu $ 4.9
Crude oil prices $ 5.00 Barrel $ 18.8
   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    $ 1.4
Crude oil prices
   $ 5.00       Barrel    $ 16.6
NGL prices
   $ 0.10       Gallon    $ 0.5
While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the ~~correlation~~relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.
The above Commodity Sensitivities Excluding Non-Cash Mark-to-Market Activity and Non-Cash Mark-to-Market Sensitivities tables exclude our collar arrangements. These collar arrangements represent approximately 5% of our commodity derivative instruments.
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 ~~correlated~~related to the price of crude oil, ~~except~~with some notable exceptions in ~~recent periods,~~late 2008 and early 2009, when NGL pricing ~~has been~~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. The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close correlation. Changes in the correlation of the price of NGLs and crude oil may cause our commodity price sensitivities to vary. 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 ~~significant~~ portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing ~~operations~~activities through ~~2013.~~
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 derivative instruments to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship.
Based on historical trends, ~~however,~~ we generally expect NGL prices to directionally follow changes in crude oil prices over the long ~~term, which~~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.~~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

97
weather, ~~and~~ the ~~domestic~~level of North American production and drilling activity ~~level~~ of exploration and production ~~companies.~~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 in the future.~~activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would ~~have a negative effect on~~reduce natural gas volumes gathered and processed, but ~~would likely~~could increase commodity ~~prices.~~
prices, if supply were to fall below demand levels.
Other Asset-Based Activities — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting, producing and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and condensate. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in time spreads and price differentials across the Pelico system to maximize the value of pipeline capacity.
Our wholesale propane logistics business 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. 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. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally 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.
We manage our commodity derivative activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure.
Valuation — Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected ~~correlations~~relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
The fair value of our interest rate swaps and commodity non-trading derivatives is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amountand/or realization of these values.

Fair Value of Contracts as of December 31, 2008
Maturity in

Maturity in
Maturity in
Maturity in
2014 and

Sources of Fair Value
Total 2009 2010-2011 2012-2013 Thereafter
(Millions)

Prices supported by quoted market prices and other external sources $ (21.7 ) $ (2.6 ) $ (15.1 ) $ (4.0 ) $ —
Prices based on models or other valuation techniques 2.0 0.3 1.7 — —

Total $ (19.7 ) $ (2.3 ) $ (13.4 ) $ (4.0 ) $ —

98
   Fair Value of Contracts as of December 31, 2010
Sources of Fair Value
   Total Maturity in
2011 Maturity in
2012-2013 �� Maturity in
2014-2015 Maturity in
2016 and
Thereafter
   (Millions)
Prices supported by quoted market prices and other external sources
   $ (90.0 ) $ (41.3 ) $ (43.7 ) $ (5.0 ) $ —
Prices based on models or other valuation techniques
   $ —    $ 0.2    $ —    $ (0.2 ) $ —

Total
   $ (90.0 ) $ (41.1 ) $ (43.7 ) $ (5.2 ) $ —

The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, our New York Mercantile Exchange, or NYMEX, ~~swap~~ positions in natural gas, NGLs and ~~our Asian-pricing NYMEX~~ crude ~~oil swaps, for which our fair value is based upon unadjusted quoted market prices for identical assets or liabilities in active markets.~~oil. In addition, this category includes our forward positions in natural gas ~~basis swaps~~ for which our forward price curves are obtained from SunGard Kiodex and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate.
The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.

99

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS


DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL STATEMENTS:

Report of Independent Registered Public Accounting Firm			~~101~~99

Consolidated Balance Sheets as of December 31, ~~2008~~2010 and ~~2007~~2009			~~102~~100

Consolidated Statements of Operations for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008			~~103~~101

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008			~~104~~102

Consolidated Statements of Changes in ~~Partners’~~ Equity for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008			~~105~~103

Consolidated Statements of Cash Flows for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008			105

Notes to Consolidated Financial Statements			106
~~Notes to Consolidated Financial Statements~~			~~107~~

~~100~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

DCP Midstream ~~Partners~~ GP, LLC

Denver, ~~Colorado:~~

Colorado

We have audited the accompanying consolidated balance sheets of DCP Midstream Partners, LP and subsidiaries (the “Company”) as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the related consolidated statements of operations, comprehensive income (loss), changes in ~~partners’~~ equity, and cash flows for each of the three years in the period ended December 31, ~~2008. Our audits also included the financial statement schedule listed in the Index at Item 15.~~2010. These financial statements ~~and financial statement schedule~~ are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements ~~and financial statement schedule~~ based on our audits. We did not audit the financial statements of Discovery Producer Services, LLC (“Discovery”), an investment of the Company which is accounted for by the use of the equity method. The Company’s equity in Discovery’s net assets of ~~$145,054,000~~$139,233,000 and ~~$161,519,000~~$145,727,000 at December 31, ~~2008~~2010 and ~~2007,~~2009, respectively, and in Discovery’s net income of ~~$13,760,000, $19,229,000,~~$20,570,000, $14,204,000 and ~~$12,033,000~~$13,759,000 for the years ended December 31, ~~2008, 2007~~2010, 2009, and ~~2006,~~2008, respectively, are included in the accompanying consolidated financial statements. Discovery’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Discovery, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, ~~the~~such consolidated ~~financial~~ statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2008,~~2010, in conformity with accounting principles generally accepted in the United States of America. ~~Also, in our opinion, such financial statement schedule when considered with the basic~~

The consolidated financial statements ~~taken as a whole, presents fairly, in all material respects, the information set forth therein.~~

~~As described in Note 1~~give retroactive effect to the ~~consolidated financial statements, through November~~April 1, ~~2006,~~2009 acquisition by the ~~portion~~Company of ~~the accompanying consolidated financial statements attributable to the wholesale propane logistics business, have been prepared~~an additional 25.1% of DCP East Texas Holdings, LLC from ~~the separate records maintained by~~ DCP Midstream, LLC, (“Midstream”) and may not necessarily be indicative of the conditions that would have existed or the results of operations if the wholesale propane logistics business had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to Midstream as a ~~whole.~~

~~Also~~combination of entities under common control, and have been accounted for in a manner similar to a pooling of interests as described in Note 1 to the consolidated financial statements through July 1, 2007, the portion of the accompanying consolidated financial statements attributable to DCP East Texas Holdings, LLC (“East Texas”) , Discovery and a nontrading derivative instrument (the “Swap”) have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed or the results of operations if East Texas, Discovery and the Swap had been operated as unaffiliated entities. Portions of certain expenses represent allocations made from, and are applicable to Midstream as a whole.

statements.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, ~~2008,~~2010, based on the criteria established in theInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March ~~4, 2009~~1, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Denver, Colorado

March ~~4, 2009~~

~~101~~1, 2011

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

December 31,
2008 2007
(Millions)

ASSETS
Current assets:
Cash and cash equivalents $ 48.0 $ 24.5
Short-term investments — 1.3
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.6 million and $1.2 million, respectively 43.6 81.7
Affiliates 36.8 52.1
Inventories 20.9 37.3
Unrealized gains on derivative instruments 15.4 3.1
Other 0.5 18.5

Total current assets 165.2 218.5
Restricted investments 60.2 100.5
Property, plant and equipment, net 629.3 500.7
Goodwill 88.8 80.2
Intangible assets, net 47.7 29.7
Equity method investments 175.4 187.2
Unrealized gains on derivative instruments 8.6 2.7
Other long-term assets 4.8 1.2

Total assets $ 1,180.0 $ 1,120.7

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade $ 44.8 $ 110.2
Affiliates 33.6 55.6
Unrealized losses on derivative instruments 17.7 30.9
Accrued interest payable 1.3 1.6
Other 27.4 21.3

Total current liabilities 124.8 219.6
Long-term debt 656.5 630.0
Unrealized losses on derivative instruments 26.0 70.0
Other long-term liabilities 8.9 5.8

Total liabilities 816.2 925.4

Non-controlling interests 34.7 26.9
Commitments and contingent liabilities
Partners’ equity:
Common unitholders (24,661,754 and 16,840,326 units issued and outstanding, respectively) 429.0 308.8
Subordinated unitholders (3,571,429 and 7,142,857 convertible units issued and outstanding, respectively) (54.6 ) (120.1 )
General partner interest (4.8 ) (5.4 )
Accumulated other comprehensive loss (40.5 ) (14.9 )

Total partners’ equity 329.1 168.4

Total liabilities and partners’ equity $ 1,180.0 $ 1,120.7


	December 31,
	2010			2009
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	6.7		$	2.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.5 million and $0.5 million, respectively		89.3			78.7
Affiliates		61.7			73.8
Inventories		65.2			34.2
Unrealized gains on derivative instruments		1.9			7.3
Assets held for sale		6.2			—
Other		2.1			1.6

Total current assets		233.1			197.7
Restricted investments		—			10.0
Property, plant and equipment, net		1,169.1			1,000.1
Goodwill		99.7			92.1
Intangible assets, net		87.0			60.5
Investments in unconsolidated affiliates		104.3			114.6
Unrealized gains on derivative instruments		1.4			2.0
Other long-term assets		6.0			4.5

Total assets	$	1,700.6		$	1,481.5

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	99.1		$	85.5
Affiliates		37.6			43.1
Unrealized losses on derivative instruments		43.0			41.5
Other		31.5			21.0

Total current liabilities		211.2			191.1
Long-term debt		647.8			613.0
Unrealized losses on derivative instruments		50.3			58.0
Other long-term liabilities		53.1			14.0

Total liabilities		962.4			876.1

Commitments and contingent liabilities:

Equity:
Common unitholders (40,478,383 and 34,608,183 units issued and outstanding, respectively)		552.2			415.5
General partner		(6.4	)		(5.9	)
Accumulated other comprehensive loss		(27.7	)		(31.9	)

Total partners’ equity		518.1			377.7
Noncontrolling interests		220.1			227.7

Total equity		738.2			605.4

Total liabilities and equity	$	1,700.6		$	1,481.5

See accompanying notes to consolidated financial statements.

~~102~~

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31,
2008 2007 2006
(Millions, except per unit amounts)

Operating revenues:
Sales of natural gas, propane, NGLs and condensate $ 678.5 $ 628.1 $ 535.1
Sales of natural gas, propane, NGLs and condensate to affiliates 477.8 297.7 232.8
Transportation, processing and other 31.2 18.5 15.0
Transportation, processing and other to affiliates 26.0 16.6 12.8
Gains (losses) from commodity derivative activity, net 75.4 (83.1 ) —
(Losses) gains from commodity derivative activity, net — affiliates (3.1 ) (4.5 ) 0.1

Total operating revenues 1,285.8 873.3 795.8

Operating costs and expenses:
Purchases of natural gas, propane and NGLs 798.3 647.4 581.2
Purchases of natural gas, propane and NGLs from affiliates 262.9 179.3 119.2
Operating and maintenance expense 43.0 32.1 23.7
Depreciation and amortization expense 36.5 24.4 12.8
General and administrative expense 12.4 14.1 12.9
General and administrative expense — affiliates 11.6 10.0 8.1
Other (1.5 ) — —

Total operating costs and expenses 1,163.2 907.3 757.9

Operating income (loss) 122.6 (34.0 ) 37.9
Interest income 5.6 5.3 6.3
Interest expense (32.8 ) (25.8 ) (11.5 )
Earnings from equity method investments 34.3 39.3 29.2
Non-controlling interest in income (3.9 ) (0.5 ) —

Income (loss) before income taxes 125.8 (15.7 ) 61.9
Income tax expense (0.1 ) (0.1 ) —

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9
Less:
Net income attributable to predecessor operations — (3.6 ) (26.6 )
General partner interest in net income (11.9 ) (2.2 ) (0.7 )

Net income (loss) allocable to limited partners $ 113.8 $ (21.6 ) $ 34.6

Net income (loss) per limited partner unit — basic and diluted $ 3.25 $ (1.05 ) $ 1.90

Weighted-average limited partner units outstanding — basic and diluted 27.4 20.5 17.5


	Year Ended December 31,
	2010			2009			2008
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	634.3		$	456.3		$	881.2
Sales of natural gas, propane, NGLs and condensate to affiliates		528.4			456.7			791.5
Transportation, processing and other		94.9			79.2			59.9
Transportation, processing and other to affiliates		20.4			16.0			26.2
(Losses) gains from commodity derivative activity, net		(7.3	)		(62.3	)		75.4
Losses from commodity derivative activity, net — affiliates		(1.2	)		(3.5	)		(3.7	)

Total operating revenues		1,269.5			942.4			1,830.5

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		755.2			529.5			1,218.0
Purchases of natural gas, propane and NGLs from affiliates		277.4			246.7			263.0
Operating and maintenance expense		79.8			69.7			77.4
Depreciation and amortization expense		73.7			64.9			53.2
General and administrative expense		14.3			11.9			13.1
General and administrative expense — affiliates		19.4			20.4			20.2
Step acquisition — equity interest re-measurement gain		(9.1	)		—			—
Other income		(1.0	)		—			(1.5	)
Other income — affiliates		(3.0	)		—			—

Total operating costs and expenses		1,206.7			943.1			1,643.4

Operating income (loss)		62.8			(0.7	)		187.1
Interest income		—			0.3			6.1
Interest expense		(29.1	)		(28.3	)		(32.8	)
Earnings from unconsolidated affiliates		23.8			18.5			18.2

Income (loss) before income taxes		57.5			(10.2	)		178.6
Income tax expense		(0.3	)		(0.6	)		(0.6	)

Net income (loss)		57.2			(10.8	)		178.0
Net income attributable to noncontrolling interests		(9.2	)		(8.3	)		(36.1	)

Net income (loss) attributable to partners		48.0			(19.1	)		141.9
Net loss (income) attributable to predecessor operations		—			1.0			(16.2	)
General partner’s interest in net income or net loss		(16.9	)		(12.7	)		(13.0	)

Net income (loss) allocable to limited partners	$	31.1		$	(30.8	)	$	112.7

Net income (loss) per limited partner unit — basic	$	0.86		$	(0.99	)	$	4.11

Net income (loss) per limited partner unit — diluted	$	0.86		$	(0.99	)	$	4.11

Weighted-average limited partner units outstanding — basic		36.1			31.2			27.4
Weighted-average limited partner units outstanding — diluted		36.1			31.2			27.4

See accompanying notes to consolidated financial statements.

~~103~~

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year Ended December 31,
2008 2007 2006
(Millions)

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9

Other comprehensive income (loss):
Reclassification of cash flow hedges into earnings 7.5 (3.1 ) (2.7 )
Net unrealized (losses) gains on cash flow hedges (33.1 ) (19.1 ) 9.6

Total other comprehensive (loss) income (25.6 ) (22.2 ) 6.9

Total comprehensive income (loss) $ 100.1 $ (38.0 ) $ 68.8


	Year Ended December 31,
	2010			2009			2008
	(Millions)
Net income (loss)	$	57.2		$	(10.8	)	$	178.0

Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings		22.9			20.6			7.5
Net unrealized losses on cash flow hedges		(18.7	)		(12.0	)		(33.1	)

Total other comprehensive income (loss)		4.2			8.6			(25.6	)

Total comprehensive income (loss)		61.4			(2.2	)		152.4
Total comprehensive income attributable to noncontrolling interests		(9.2	)		(8.3	)		(36.1	)

Total comprehensive income (loss) attributable to partners	$	52.2		$	(10.5	)	$	116.3

See accompanying notes to consolidated financial statements.

~~104~~

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN ~~PARTNERS’~~ EQUITY

Accumulated

General
Other
Total

Predecessor
Common
Class C
Subordinated
Partner
Comprehensive
Partners’

Equity Unitholders Unitholders Unitholders Interest Income (Loss) Equity
(Millions)

Balance, January 1, 2006
$ 219.8 $ 215.8 $ — $ (109.7 ) $ (5.6 ) $ 0.4 $ 320.7
Net change in parent advances (25.4 ) — — — — — (25.4 )
Acquisition of wholesale propane logistics business (56.7 ) — — — — — (56.7 )
Excess purchase price over acquired assets — — (26.3 ) — — — (26.3 )
Issuance of 200,312 Class C units — — 5.6 — — — 5.6
Proceeds from general partner interest (represented by 4,088 equivalent units) — — — — 0.1 — 0.1
Contributions by unitholders — — — 2.8 0.2 — 3.0
Distributions to unitholders — (12.8 ) (0.1 ) (8.8 ) (0.4 ) — (22.1 )
Net income attributable to predecessor operations 26.6 — — — — — 26.6
Net income — 20.4 0.1 14.1 0.7 — 35.3
Other comprehensive income — — — — — 6.9 6.9

Balance, December 31, 2006
164.3 223.4 (20.7 ) (101.6 ) (5.0 ) 7.3 267.7
Net change in parent advances (14.6 ) — — — — — (14.6 )
Acquisition of East Texas, Discovery and the Swap (153.3 ) 27.0 — — 0.6 — (125.7 )
Excess purchase price over acquired assets — (118.0 ) — — — — (118.0 )
Acquisition of Momentum Energy Group, Inc. — 12.0 — — — — 12.0
Purchase of units — (0.3 ) — — — — (0.3 )
Issuance of units — 0.3 — — — — 0.3
Issuance of 5,386,732 common units — 228.5 — — — — 228.5
Conversion of Class C units to common units — (20.7 ) 20.7 — — — —
Contributions by unitholders — 0.2 — 0.6 — — 0.8
Distributions to unitholders — (27.0 ) (0.2 ) (14.1 ) (3.2 ) — (44.5 )
Equity-based compensation — 0.2 — — — — 0.2
Net income attributable to predecessor operations 3.6 — — — — — 3.6
Net income (loss) — (16.8 ) 0.2 (5.0 ) 2.2 — (19.4 )
Other comprehensive loss — — — — — (22.2 ) (22.2 )

Balance, December 31, 2007
— 308.8 — (120.1 ) (5.4 ) (14.9 ) 168.4
Issuance of 4,250,000 common units — 132.1 — — — — 132.1
Conversion of subordinated units to common units (66.4 ) — 66.4 — — —
Contributions by unitholders — 4.0 — — — — 4.0
Distributions to unitholders and general partner — (53.9 ) — (10.5 ) (11.3 ) — (75.7 )
Equity-based compensation — 0.2 — — — — 0.2
Net income — 104.2 — 9.6 11.9 — 125.7
Other comprehensive loss — — — — — (25.6 ) (25.6 )

Balance, December 31, 2008
$ — $ 429.0 $ — $ (54.6 ) $ (4.8 ) $ (40.5 ) $ 329.1


	Partners’ Equity
	Predecessor Equity		Common Unitholders			Class D Unitholders		Subordinated Unitholders		General Partner			Accumulated Other Comprehensive Income (Loss)			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	)
Issuance of 5,870,200 common units		—		189.1			—		—		—			—			—			189.1
Equity based compensation		—		0.2			—		—		—			—			—			0.2
Distributions to unitholders and general partner		—		(85.6	)		—		—		(16.3	)		—			—			(101.9	)
Distributions to noncontrolling interests		—		—					—		—			—			(25.6	)		(25.6	)
Contributions from DCP Midstream, LLC		—		0.6			—		—		—			—			—			0.6
Contributions from noncontrolling interests		—		—			—		—		—			—			14.3			14.3
Excess purchase price over carrying value of acquired assets		—		(0.8	)		—		—		—			—			—			(0.8	)

Comprehensive income:
Net income		—		32.2			—		—		15.8			—			9.2			57.2
Reclassification of cash flow hedges into earnings		—		—			—		—		—			22.9			—			22.9
Net unrealized losses on cash flow hedges		—		—			—		—		—			(18.7	)		—			(18.7	)

Total comprehensive income (loss)		—		32.2			—		—		15.8			4.2			9.2			61.4

Balance, December 31, 2010	$		$	552.2		$	—	$	—	$	(6.4	)	$	(27.7	)	$	220.1		$	738.2

See accompanying notes to consolidated financial statements.

~~105~~

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~CHANGES IN EQUITY — (Continued)

Year Ended December 31,
2008 2007 2006
(Millions)

OPERATING ACTIVITIES:
Net income (loss) $ 125.7 $ (15.8 ) $ 61.9
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense 36.5 24.4 12.8
Earnings from equity method investments, net of distributions 25.6 (0.4 ) (3.3 )
Non-controlling interest in income 3.9 0.5 —
Other, net (0.4 ) (0.2 ) (2.4 )
Change in operating assets and liabilities which provided (used) cash, net of effects of acquisitions:
Accounts receivable 55.4 (42.2 ) 43.1
Inventories 16.4 (7.2 ) 11.6
Net unrealized (gains) losses on derivative instruments (101.0 ) 81.1 (0.1 )
Accounts payable (79.7 ) 38.9 (31.5 )
Accrued interest (0.3 ) 0.5 0.3
Other current assets and liabilities 19.8 (16.4 ) 2.0
Other long-term assets and liabilities (0.4 ) 2.2 0.4

Net cash provided by operating activities 101.5 65.4 94.8

INVESTING ACTIVITIES:
Capital expenditures (41.0 ) (21.3 ) (27.2 )
Acquisition of Michigan Pipeline & Processing, LLC, net of cash acquired (146.4 ) — —
Acquisition of subsidiaries of Momentum Energy Group, Inc., net of cash acquired (10.9 ) (142.0 ) —
Acquisition of assets — (191.3 ) —
Acquisition of equity method investments — (153.3 ) —
Investments in equity method investments (13.8 ) (16.3 ) (11.1 )
Payment of earnest deposit — (9.0 ) —
Refund of earnest deposit — 9.0 —
Acquisition of wholesale propane logistics business — — (56.7 )
Proceeds from sales of assets 2.9 0.1 0.3
Purchases of available-for-sale securities (608.2 ) (6,921.6 ) (7,372.4 )
Proceeds from sales of available-for-sale securities 650.5 6,924.0 7,373.3

Net cash used in investing activities (166.9 ) (521.7 ) (93.8 )

FINANCING ACTIVITIES:
Proceeds from debt 660.4 579.0 78.0
Payments of debt (633.9 ) (217.0 ) (20.1 )
Payment of deferred financing costs — (0.6 ) (0.2 )
Purchase of units — (0.3 ) —
Proceeds from issuance of common units, net of offering costs 132.1 228.5 —
Proceeds from issuance of equivalent units to general partner — — 0.1
Excess purchase price over acquired assets — (100.3 ) (10.7 )
Net change in advances from DCP Midstream, LLC — (14.6 ) (25.4 )
Distributions to unitholders and general partner (76.2 ) (44.0 ) (22.1 )
Distributions to non-controlling interests (3.3 ) — —
Contributions from non-controlling interests 5.7 3.4 —
Contributions from DCP Midstream, LLC 4.1 0.5 3.4

Net cash provided by financing activities 88.9 434.6 3.0

Net change in cash and cash equivalents 23.5 (21.7 ) 4.0
Cash and cash equivalents, beginning of period 24.5 46.2 42.2

Cash and cash equivalents, end of period $ 48.0 $ 24.5 $ 46.2


	Partners’ Equity
	Predecessor Equity			Common Unitholders			Class D Unitholders			Subordinated Unitholders			General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2008	$	64.0		$	308.8		$	—		$	(120.1	)	$	(5.4	)	$	(14.9	)	$	155.1		$	387.5
Net change in parent advances		(14.2	)		—			—			—			—			—			—			(14.2	)
Issuance of 4,250,000 common units		—			132.1			—			—			—			—			—			132.1
Conversion of subordinated units to common units		—			(66.4	)		—			66.4			—			—			—			—
Contributions		—			4.0			—			—			—			—			—			4.0
Contributions from noncontrolling interests		—			—			—			—			—			—			21.3			21.3
Distributions		—			(53.9	)		—			(10.5	)		(11.3	)		—			—			(75.7	)
Distributions to noncontrolling interests		—			—			—			—			—			—			(46.4	)		(46.4	)
Equity-based compensation		—			0.2			—			—			—			—			—			0.2
Acquisition of subsidiaries		—			—			—			—			—			—			1.6			1.6

Comprehensive income:
Net income attributable to predecessor operations		16.2			—			—			—			—			—			—			16.2
Net income		—			104.2			—			9.6			11.9			—			36.1			161.8
Reclassification of cash flow hedges into earnings		—			—			—			—			—			7.5			—			7.5
Net unrealized losses on cash flow hedges		—			—			—			—			—			(33.1	)		—			(33.1	)

Total comprehensive income (loss)		16.2			104.2			—			9.6			11.9			(25.6	)		36.1			152.4

Balance, December 31, 2008	$	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		—			(67.7	)		(2.1	)		(2.1	)		(13.4	)		—			—			(85.3	)
Distributions to noncontrolling interests		—			—			—			—			—			—			(27.0	)		(27.0	)
Contributions from DCP Midstream, LLC		—			0.7			—			—			—			—			—			0.7
Contributions from noncontrolling interests		—			—			—			—			—			—			78.7			78.7
Other		—			(0.1	)		—			—			—			—			—			(0.1	)
Issuance of 2,875,000 common units		—			69.5			—			—			—			—			—			69.5
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 carrying value of acquired assets		—			—			19.0			—			—			—			—			19.0
Conversion of Class D units into common units		—			66.8			(66.8	)		—			—			—			—			—

Comprehensive income:
Net loss attributable to predecessor operations		(1.0	)		—			—			—			—			—			—			(1.0	)
Net (loss) income		—			(30.6	)		(4.4	)		4.6			12.3			—			8.3			(9.8	)
Reclassification of cash flow hedges into earnings		—			—			—			—			—			20.6			—			20.6
Net unrealized losses on cash flow hedges		—			—			—			—			—			(12.0	)		—			(12.0	)

Total comprehensive (loss) income		(1.0	)		(30.6	)		(4.4	)		4.6			12.3			8.6			8.3			(2.2	)

Balance, December 31, 2009	$	—		$	415.5		$	—		$	—		$	(5.9	)	$	(31.9	)	$	227.7		$	605.4

See accompanying notes to consolidated financial statements.

~~106~~

DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
   Year Ended December 31,
   2010 2009 2008
   (Millions)
OPERATING ACTIVITIES:

Net income (loss)
   $ 57.2    $ (10.8 ) $ 178.0
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization expense
   73.7    64.9    53.2
Earnings from unconsolidated affiliates
   (23.8 ) (18.5 ) (18.2 )
Distributions from unconsolidated affiliates
   30.0    20.2    38.4
Step acquisition — equity interest re-measurement gain
   (9.1 ) —    —
Other, net
   —    (0.4 ) (0.7 )
Change in operating assets and liabilities which provided (used) cash, net of effects of acquisitions:

Accounts receivable
   5.8    (36.6 ) 101.4
Inventories
   (8.7 ) (13.3 ) 16.4
Net unrealized losses (gains) on derivative instruments
   4.0    83.8    (101.0 )
Accounts payable
   5.7    21.5    (108.2 )
Accrued interest
   1.8    (0.6 ) (0.3 )
Other current assets and liabilities
   2.6    (3.2 ) 19.0
Other long-term assets and liabilities
   1.6    0.9    (0.4 )

Net cash provided by operating activities
   140.8    107.9    177.6

INVESTING ACTIVITIES:

Capital expenditures
   (50.7 ) (164.8 ) (72.7 )
Acquisitions, net of cash acquired
   (203.3 ) (44.5 ) (157.3 )
Investments in unconsolidated affiliates
   (2.3 ) (7.0 ) (7.4 )
Return of investment from unconsolidated affiliate
   1.2    2.2    —
Proceeds from sales of assets
   3.4    0.3    2.9
Purchases of available-for-sale securities
   —    (1.1 ) (608.2 )
Proceeds from sales of available-for-sale securities
   10.1    51.1    650.5

Net cash used in investing activities
   (241.6 ) (163.8 ) (192.2 )

FINANCING ACTIVITIES:

Proceeds from debt
   868.2    237.0    660.4
Payments of debt
   (833.4 ) (280.5 ) (633.9 )
Payment of deferred financing costs
   (2.1 ) —    —
Proceeds from issuance of common units, net of offering costs
   189.3    69.5    132.1
Net change in advances to predecessor from DCP Midstream, LLC
   —    3.0    (14.2 )
Distributions to unitholders and general partner
   (101.9 ) (85.3 ) (76.2 )
Distributions to noncontrolling interests
   (25.6 ) (27.0 ) (46.4 )
Contributions from noncontrolling interests
   13.8    78.7    21.3
Contributions from DCP Midstream, LLC
   0.6    0.7    4.1
Purchase of additional interest in a subsidiary
   (3.5 ) —    —

Net cash provided by (used in) financing activities
   105.4    (3.9 ) 47.2

Net change in cash and cash equivalents
   4.6    (59.8 ) 32.6
Cash and cash equivalents, beginning of period
   2.1    61.9    29.3

Cash and cash equivalents, end of period
   $ 6.7    $ 2.1    $ 61.9

See accompanying notes to consolidated financial statements.
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008

1.
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,~~gas; producing, transporting, storing and selling ~~propane and transporting and selling~~ NGLs and condensate.

We are a Delaware ~~master~~ 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 (acquired in May 2007);~~system; our 40% limited liability company ~~interests~~interest in ~~DCP East Texas Holdings, LLC, or East Texas, and~~ Discovery Producer Services LLC, or ~~Discovery (acquired in July 2007);~~Discovery; our Wyoming ~~system and~~system; a ~~70%~~75% interest in our Colorado system ~~(each~~(of which 5% was acquired in ~~August 2007)~~February 2010); our 50.1% interest in our East Texas system (of which 25.1% was acquired in April 2009); our Michigan ~~systems~~system (acquired in October ~~2008)~~2008 and November 2009); our wholesale propane logistics business ~~(acquired~~(which includes Atlantic Energy acquired in ~~November 2006)~~July 2010); and our NGL ~~transportation pipelines.~~

logistics business (including Marysville Hydrocarbons Holdings, Inc, or Marysville, acquired in December 2010, the Wattenberg pipeline acquired in January 2010 and our 100% interest in the Black Lake Pipeline Company, or Black Lake, 55% of which was acquired in July 2010, comprised of a 5% interest acquired from DCP Midstream, LLC, in a transaction among entities under common control, and an additional 50% interest acquired from an affiliate of BP PLC).
Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, ~~which~~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 most of our assets. DCP Midstream, LLC owns approximately 30% of ~~our partnership.~~

us.
The 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 consolidated financial statements include our accounts, and prior to December 7, 2005 the assets, liabilities and operations contributed to us by DCP Midstream, LLC and its wholly-owned subsidiaries, which we refer to as DCP Midstream Partners Predecessor, upon the closing of our initial public offering, which have been combined with the historical assets, liabilities and operations of our ~~wholesale propane logistics business which we acquired~~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 ~~November 2006, and~~April 2009 as our ~~25%~~“predecessor.” Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas, ~~our 40%~~we owned a 25.0% limited liability company interest in ~~Discovery,~~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 ~~non-trading derivative instrument, or~~consolidated subsidiary.Because the ~~Swap, which DCP Midstream, LLC entered into~~additional interest in ~~March 2007, which we~~East Texas was acquired from DCP Midstream, LLC, ~~in July 2007. These were transactions~~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 our ~~wholesale propane logistics business, Discovery and~~additional 25.1% interest in 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. In addition, the results of operations of our Southern Oklahoma, Wyoming and Colorado systems, and our Michigan systems, have been included in the consolidated financial statements since their respective acquisition dates.

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. We refer to DCP Midstream Partners Predecessor, the assets, liabilities and operations of our wholesale propane logistics business, our equity, ~~interests in East Texas and Discovery, and the Swap, prior to our acquisition from DCP Midstream, LLC, collectively as our “predecessors.”~~respectively. The consolidated financial statements of our ~~predecessors~~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 ~~predecessors~~ predecessor
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
had been operated as an unaffiliated entity. In addition, the results of operations of acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates.
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All ~~significant~~ 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.

~~107~~

~~DCP MIDSTREAM PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

2.
2.	Summary of Significant Accounting Policies

Use of Estimates— Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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.

Cash and Cash Equivalents— We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less to be cash equivalents.

Short-Term and Restricted Investments— We may invest available cash balances in various financial instruments, such as commercial paper and money market ~~instruments and tax-exempt debt securities that have stated maturities of 20 years or more.~~instruments. These instruments provide for a high degree of liquidity through features which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted.

Restricted investments are used as collateral to secure the term loan portion of our credit facility and to finance gathering and compression asset acquisitions. We ~~have classified~~classify all short-term and restricted investments as available-for-sale as we do not intend to hold them to maturity, nor are they bought or sold with the objective of generating profit on short-term differences in prices. These investments are recorded at fair value, with changes in fair value recorded as unrealized gains and losses in accumulated other comprehensive income (loss), or AOCI. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by ~~us, and as~~us; interest rates are re-set on a daily, weekly or monthly basis.

Inventories— Inventories, which consist primarily of ~~propane,~~NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Property, Plant and Equipment— Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability of a conditional asset retirement obligation as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing

~~and/or~~ ~~method of settlement are conditional on a future event that may or may not be within the control of the entity.~~

Goodwill and Intangible Assets— Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We ~~evaluate~~perform an annual impairment test of goodwill ~~for impairment annually~~ in the third quarter, and ~~whenever~~update the test during interim periods when we believe events or changes in circumstances indicate ~~it is more likely than~~that we may not ~~that~~be able to recover the ~~fair~~carrying value of a reporting ~~unit is less than its carrying amount.~~unit. Impairment testing ~~of goodwill~~ consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, the excess of the carrying value over the fair value is recognized as an impairment loss.

~~108~~

We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Intangible assets consist primarily of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit.
Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.
Long-Lived Assets— We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
significant adverse change in legal factors or business climate;
a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
• ~~significant adverse change in legal factors or business climate;~~
• a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
• ~~an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;~~
• ~~significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;~~
• ~~a significant adverse change in the market value of an asset; or~~
• ~~a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.~~
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;
a significant adverse change in the market value of an asset; or
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
~~Equity Method Investments~~Asset Retirement Obligations — Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.
Investments in Unconsolidated Affiliates— We use the equity method to account for 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.
We evaluate our ~~equity method~~ investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our ~~equity method~~
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is considered to be permanently less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
Unamortized Debt Expense— Expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. These expenses are recorded on the consolidated balance sheet as other long-term assets.
~~Non-Controlling~~Noncontrolling Interest— ~~Non-controlling~~Noncontrolling interest represents ~~(1) the non-controlling~~any third party or affiliate interest ~~holders ownership interests~~ in ~~the net assets of Collbran Valley Gas Gathering, a joint venture acquired in conjunction with the MEG acquisition in August 2007; and (2) the non controlling interest holders’ portion of the net~~

~~109~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~assets of Jackson Pipeline Company, a partnership~~non-wholly-owned entities that we ~~acquired with the Michigan acquisition in October 2008.~~consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as ~~non-controlling interest.~~noncontrolling interest in equity. Distributions to and contributions from ~~non-controlling~~noncontrolling interests represent cash payments to and cash contributions from, respectively, ~~from~~ such ~~third-party~~third party and affiliate investors.
Accounting for Risk Management Activities and Financial Instruments — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow protection activities. We are using the mark-to-market method of accounting for all commodity derivative instruments beginning in July 2007. As a result, the remaining net loss deferred in AOCI will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings.
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings.
~~All derivative activity reflected in the consolidated financial statements for our predecessors was transacted by us or by DCP Midstream, LLC and its subsidiaries, and transferredand/or~~ allocated to us. All derivative activity reflected in the consolidated financial statements, which is not related to our predecessors, has been and will be transacted by us. Prior to July 1, 2007, we designated eachNon-trading energy commodity ~~derivative as either trading or non-trading. Certain non-trading~~ derivatives ~~were further~~are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal ~~sales, while certain~~sales. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchases or normal sale exception are ~~designated as non-trading derivative activity. For the periods presented, we did~~ not ~~have any trading derivative activity, however, we did have cash flow and~~elected, are recorded at fair value ~~hedge activity, normal purchases and normal sales activity, and non-trading derivative activity included~~ in the consolidated ~~financial statements.~~balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:
Classification of Contract

Accounting Method

~~Classification of Contract~~
~~Accounting Method~~
Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity
Mark-to-market ~~method(b)~~method (a) Net basis in gains and losses from commodity derivative activity
Cash Flow ~~Hedge(a)~~Hedge
Hedge ~~method(c)~~method (b) Gross basis in the same consolidated statements of operations category as the related hedged item
Fair Value ~~Hedge(a)~~Hedge
Hedge ~~method(c)~~method (b) Gross basis in the same consolidated statements of operations category as the related hedged item
Normal Purchases or Normal Sales
Accrual ~~method(d)~~method (c) Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale
(a) Effective July 1, 2007, all commodity cash flow hedges are classified as non-trading derivative activity. Our interest rate swaps continue to be accounted for as cash flow hedges. As of December 31, 2007 we no longer use fair value hedges.
~~(b)~~ Mark-to-market method — An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.
~~(c)~~ (b) Hedge method — An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the

~~110~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.
~~(d)~~ (c) Accrual method — An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Cash Flow and Fair Value Hedges — For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in partners’ equity as AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same accounts as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.
The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.
Valuation — When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical ~~and expected correlations~~relationships with quoted market prices and the expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Revenue Recognition— We generate the majority of our revenues from gathering, processing, compressing, transporting, storing and fractionating natural gas and NGLs, and from trading and marketing of natural gas and NGLs. We realize revenues either by selling the residue natural gas and NGLs, or by receiving ~~fees from the producers.~~

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fees.
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:
•
Fee-based arrangements —Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, storing or transporting natural gas; and storing and transporting NGLs. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.
•
~~Percent-of-proceeds~~Percent-of-proceeds/liquids arrangements— Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and ~~NGLs~~condensate based on index prices from published index market prices. We remit to the producers either anagreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and ~~NGLs,~~condensate, or anagreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and ~~the NGLs,~~condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in our returning all or a portion of the residue natural gasand/or the NGLs to the producer, in lieu of returning sales proceeds. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements ~~correlate~~relate directly with the price of natural gas,~~and/or~~ NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate. ~~NGLs.~~
•
Propane sales arrangements— Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to retail propane distributors, who in turn resell to their retail customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their retail customers.
Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.
We recognize revenues for sales and services under the four revenue recognition criteria, as follows:
•
Persuasive evidence of an arrangement exists— Our customary practice is to enter into a written ~~contract, executed by both us and the customer.~~contract.
•
Delivery— Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.
•
The fee is fixed or determinable— We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.
•
~~Collectibility~~Collectability is ~~probable~~reasonably assured— ~~Collectibility~~Collectability is evaluated on acustomer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If ~~collectibility~~collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

~~112~~

~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for non-trading commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity derivative ~~activity.~~ activity.These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial or physical energy trading contracts.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as ~~other receivables~~accounts receivable or ~~other payables~~accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable — trade and accounts receivable — affiliates were imbalances of $3.8 million and $1.6 million at December 31, 2008 and 2007, respectively. Included in the consolidated balance sheets as accounts payable — trade were imbalances of $1.4 million and $1.1 million at December 31, 2008 and 2007, respectively.
Significant ~~Customer~~Customers— There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006. In addition, there were no~~2008. There was one third party ~~customers~~customer that accounted for ~~more than 10%~~approximately 17%, 12% and 11% of total operating revenues of the Wholesale Propane Logistics segment for the years ended December 31, 2010, 2009 and 2008, ~~2007 and 2006 in any of our business segments.~~respectively. We also had significant transactions with ~~affiliates, and with suppliers of natural gas and propane.~~
affiliates.
Environmental Expenditures— Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessmentsand/~~orclean-ups~~or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, ~~2008~~2010 and ~~2007,~~2009, included in the consolidated balance sheets as other current liabilities amounted to ~~$1.3~~$0.6 million and ~~$0.7~~$0.5 million, respectively, and as other long-term liabilities amounted to $1.3 million and $0.6 million, ~~and $1.0 million,~~ respectively.
Equity-Based Compensation— Equity classified stock-based compensation cost is measured at fair value, based on the closing common unit price at grant date, and is recognized as expense over the vesting period. Liability classified stock-based compensation cost is remeasured at each reporting date at fair value, based on the closing common unit price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Awards granted to non-employees for acquiring, or in conjunction with selling, goods and services are measured at the estimated fair value of the goods or services, or the fair value of the award, whichever is more reliably measured.
Allowance for Doubtful Accounts — Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.
Income Taxes— We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal returns of each partner.
~~Comprehensive Income or Loss~~— Comprehensive income or loss consists of net income or loss and other comprehensive income or loss, which includes unrealized gains and losses on the effective portion of derivative instruments classified as cash flow hedges.

~~113~~

~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Net Income or Loss per Limited Partner Unit— Basic and diluted net income or loss per limited partner unit is calculated by dividing limited partners’ interest in net income or loss ~~less pro forma general partner incentive distributions,~~ by the weighted-average number of outstanding limited partner units during the period.
3.
3. Recent Accounting Pronouncements

~~Statement of Financial Accounting Standards, or SFAS, No. 162 “The Hierarchy of Generally Accepted Accounting Principles,”~~~~or SFAS 162— In May 2008, the~~ Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations”,or ASU 2010-29 — In December 2010, the FASB issued ~~SFAS 162,~~ASU 2010-29 which ~~is intended~~amended Accounting Standards Codification, or ASC, Topic 805 “Business Combinations” to ~~improve financial reporting by identifying~~specify that if a ~~consistent framework, or hierarchy, for selecting accounting principles to be used in preparing~~public

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

entity presents comparative financial statements, ~~that are presented in conformity with GAAP for nongovernmental entities. SFAS 162 is effective 60 days following~~ the ~~Securities~~entity should disclose revenue and ~~Exchange Commission, or SEC, approval~~earnings of the ~~Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We have assessed~~combined entity as though the ~~impact~~business combination that occurred during the year had occurred as of the ~~adoption of SFAS 162, and believe that there will be no impact on our consolidated results of operations, cash flows or financial position.~~

~~FASB Staff Position, or FSP,No. SFAS 142-3~~ ~~“Determination~~beginning of the ~~Useful Life~~comparable prior annual reporting period only. The ASU also expands the supplemental pro forma disclosures under Topic 805 to include a description of ~~Intangible Assets,”~~or~~FSP 142-3— In April 2008,~~ the ~~FASB issuedFSP 142-3,~~ ~~which amends~~nature and the ~~factors that should be considered~~amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in ~~developing renewal or extension assumptions used to determine~~ the ~~useful life of a recognized intangible.FSP 142-3~~reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after January 1, 2011 and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.

ASU 2010-28 “Intangibles—Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for ~~fiscal years~~Reporting Units with Zero or Negative Carrying Amounts”,or ASU 2010-28 — In December 2010, the FASB issued ASU 2010-28 which amended ASC Topic 350 “Goodwill and Other”. ASU 2010-28 requires an entity with reporting units that have carrying amounts that are zero or negative to assess whether it is more likely than not that the reporting units’ goodwill is impaired. If the entity determines that it is more likely than not that the goodwill of one or more of its reporting units is impaired, the entity is required to perform Step 2 of the goodwill impairment test for those reporting unit(s) and record any resulting impairment as a cumulative-effect adjustment to beginning retained earnings. The provisions of ASU 2010-28 became effective for us on January 1, 2011, and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.

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 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 became 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 ~~15, 2008,~~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 ~~interim periods within those fiscal years. We are~~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 consolidated financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements”,or ASU 2009-13 — In October 2009, the ~~process of assessing~~FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the ~~impact ofFSP 142-3,~~ ~~but do not expect~~accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a ~~material~~combined unit. ASU 2009-13 became effective for us on January 1, 2011 and there was no impact on our consolidated results of operations, cash flows and financial position as a result of adoption.

~~SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133~~~~,” or SFAS 161~~— In March 2008, the FASB issued SFAS 161, which requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our disclosures, and will make the required disclosures in our March 31, 2009 consolidated financial statements.

~~SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51~~~~,” or SFAS 160 —~~ In

4.	Acquisitions

On December 2007, the FASB issued SFAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 was effective for us on January 1, 2009, and did not have a significant impact on our consolidated results of operations, cash flows or financial position. As a result of adoption effective January 1, 2009,30, 2010, we ~~will reclassify non-controlling interests in the consolidated balance sheets to partners’ equity.~~

~~SFAS No. 141(R) “Business Combinations (revised 2007)~~~~,” or SFAS 141(R) —~~ ~~In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all (and only) the assets~~ acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively upon adoption, we will account for allinterests in Marysville Hydrocarbons Holdings, LLC, or Marysville. The acquisition involved three separate transactions with ~~closing dates subsequent to~~a number of parties. The Partnership acquired a 90% interest in Marysville from Dart Energy Corporation, a 5% interest in Marysville from Prospect Street Energy, LLC and 100% of EE Group, LLC, which owns the ~~adoption date~~remaining 5% interest in ~~accordance with the provisions of the standard.~~

~~114~~

Marysville. We

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

~~SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115~~~~,” or SFAS 159~~— In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. The provisions of SFAS 159 became effective for us on January 1, 2008. We have not elected the fair value option relative to any of our financial assets and liabilities which are not otherwise required to be measured at fair value by other accounting standards. Therefore, there is no effect of adoption reflected in our consolidated results of operations, cash flows or financial position.

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


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

	•	~~establishes a framework for measuring fair value;~~

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

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

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

~~FSPNo. 157-3~~ ~~“Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,”~~or~~FSP 157-3— In October 2008, the FASB issuedFSP 157-3,~~ which provides guidance in situations where a) observable inputs do not exist, b) observable inputs exist but only in an inactive market and c) how market quotes should be considered when assessing the relevance of observable and unobservable inputs to determine fair value.~~FSP 157-3~~ was effective upon issuance, including prior periods for which financial statements have not been issued. We believe that the financial assets that are reflected in our financial statements are transacted within active markets, and therefore, there is no effect on our consolidated results of operations, cash flows or financial positions as a result of the adoption of this FSP.

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~~DCP MIDSTREAM PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~FSP of Financial Interpretation, or FIN,39-1,~~ ~~“Amendment of FASB Interpretation No. 39,”~~~~or FSPFIN 39-1— In April 2007, the FASB issued FSPFIN 39-1,~~ which permits, but does not require, a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP~~FIN 39-1~~ became effective for us beginning on January 1, 2008; however, we have elected to continue our policy of reflecting our derivative asset and liability positions, as well as any cash collateral, on a gross basis in our consolidated balance sheets.

~~EITF 08-06~~ ~~“Equity Method Investment Accounting Considerations~~~~,” orEITF 08-06 —In November 2008, the EITF issued ETIF08-06.~~ Although the issuance of FAS 141(R) and FAS 160 were not intended to reconsider the accounting for equity method investments, the application of the equity method is affected by the issuance of these standards. This issue addresses a) how the initial carrying value of an equity method investment should be determined; b) how an impairment assessment of an underlying indefinite-lived intangible asset of an equity method investment should be performed; c) how an equity method investee’s issuance of shares should be accounted for and d) how to account for a change in an investment from the equity method to the cost method. This issue is effective for us on January 1, 2009, and although we do not expect any changes to the manner in which we apply equity method accounting, this guidance will be considered on a prospective basis to transactions with equity method investees.

~~EITF 07-04~~ ~~“Application of the Two — Class Method under FASB Statement No. 128 to Master Limited Partnerships”~~or~~EITF 07-04 —In March 2008, the EITF issued ETIF07-04.~~ This issue seeks to improve the comparability of earnings per unit, or EPU, calculations for master limited partnerships with incentive distribution rights in accordance with FASB Statement No. 128 and its related interpretations. This issue is effective for us on January 1, 2009 and will be incorporated into our EPU calculations beginning with the quarter ending March 31, 2009. We are in the process of assessing the impact of~~EITF 07-04~~ ~~on our EPU calculations, and will make any required changes to our calculation methodology for the quarter ending March 31, 2009.~~


4.	~~Acquisitions~~

~~Gathering and Compression Assets~~

On October 1, 2008, we acquired Michigan Pipeline & Processing, LLC, or MPP, a privately held company engaged in natural gas gathering and treating services for natural gas produced from the Antrim Shale of northern Michigan and natural gas transportation within Michigan. The results of MPP’s operations have been included in the consolidated financial statements since that date. Under the terms of the acquisition, we paid a purchase price of ~~$145.0~~$94.8 million ~~plus~~and $6.0 million for net working capital and other adjustments for an aggregate purchase price of ~~$3.4~~$100.8 million subject to ~~additional~~ customary purchase price ~~adjustments. We may pay up~~adjustments, for our 100% interest. The cash purchase was financed at closing with borrowings under the Partnership’s revolving credit facility. $21.2 million of the purchase price has been deposited in an indemnity escrow to ~~an additional $15.0~~satisfy certain tax liabilities and provide for breaches of representations and warranties of the sellers.

On January 4, 2011, we merged two wholly-owned subsidiaries of Marysville and converted the combined entity’s organizational structure from a corporation to a limited liability company. This conversion to a limited liability company triggers tax liabilities, resulting from built-in tax gains recognized in the transaction, to become currently payable. Accordingly, $35.0 million of estimated deferred tax liabilities associated with this transaction and recorded at December 31, 2010, became currently payable as of January 4, 2011. These tax liabilities are unrelated to the ~~sellers depending on~~tax liabilities of Marysville for which the earnings of the assets after a three-year period. We financed the acquisition through utilization of our credit facility. In addition, we entered into a separate agreement that provides the seller with available treating capacity on certain Michigan assets. The seller agreed to pay up to $1.5 million annually for up to nine years if they do not meet certain criteria, including providing additional volumes for treatment.indemnity escrow has been established. These ~~payments would reduce goodwill as a return of purchase price. This agreement~~tax liabilities may be ~~terminated earlier if certain performance criteria of Michigan assets are satisfied. Certain of these performance criteria were satisfied, and as a result,~~greater or less than the ~~amount was reduced to approximately $0.8~~$35.0 million ~~per year~~currently recorded in our balance sheet as of December 31, ~~2008. We initially held a $25.0 million letter~~2010 depending on the final accounting for the Marysville business combination.

Given the recent timing of ~~credit to secure~~this acquisition, we have not completed the ~~seller’s performance under this agreement~~accounting for the Marysville business combination and ~~to secure~~have not made certain disclosures. These disclosures include the ~~seller’s indemnification obligation under the acquisition agreement; however as a result~~final fair value of the satisfaction of certain performance conditions, this amount was reduced to approximately $22.5 million as of December 31, 2008. The fees under the Omnibus Agreement increased $0.4 million per year effective October 1, 2008, in connection with the acquisition.

~~116~~

~~DCP MIDSTREAM PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~Under the purchase method of accounting, the~~ assets acquired and liabilities assumed and pro-forma information. The final accounting and related disclosures for business combinations will be made in subsequent financial statements. The purchase price allocation is preliminary and is based on estimates of ~~MPP were recorded at their respective~~ fair values ~~as of~~at the date of the ~~acquisition,~~acquisition. Currently, all amounts included in property, plant and ~~we recorded goodwill~~equipment are classified as processing, storage and terminal facilities. This allocation may change in subsequent financial statements. We are currently evaluating the preliminary purchase price allocation, which will be adjusted as additional information relative to the fair value of ~~approximately $6.7 million. The goodwill amount recognized relates primarily to projected growth from new customers. The values of certain~~ assets and liabilities ~~are~~becomes available. The preliminary ~~and are subject to adjustment as additional information is obtained, which when finalized may result in material adjustments. The~~ purchase price allocation is as follows:

(Millions)

Cash $ 1.7
Accounts receivable 2.1
Other assets 0.1
Other long term assets 3.8
Property, plant and equipment 116.1
Goodwill 6.7
Intangible assets 20.0
Other liabilities (0.5 )
Non-controlling interest in joint venture (1.6 )

Total purchase price allocation $ 148.4

~~In August 2007,~~


	(Millions)
Aggregate consideration	$	100.8

Cash		3.1
Accounts receivable		1.1
Inventory		5.7
Other current assets		0.7
Property, plant and equipment		129.9
Accounts payable		(0.7	)
Other current liabilities		(4.0	)
Long-term liabilities		(35.0	)

Total preliminary purchase price allocation	$	100.8
			��

On July 30, 2010, we acquired ~~certain subsidiaries~~Atlantic Energy, a wholly-owned subsidiary of ~~Momentum Energy Group, Inc., or MEG, from DCP Midstream, LLC~~UGI Corporation, for ~~approximately $165.8 million. As a result~~$49.0 million plus propane inventory and other working capital of the acquisition, we expanded our operations into the Piceance and Powder River producing basins, thus diversifying our business into new operating areas. The consideration consisted of approximately $153.8 million of cash and the issuance of 275,735 common units to an affiliate of DCP Midstream, LLC that were valued at approximately $12.0$17.3 million. We have incurred additional post-closing purchase price adjustments ~~totaling $10.9 million~~ for net working capital ~~and general and administrative charges. We~~of $1.9 million for an aggregate purchase price of $68.2 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. The cash purchase was financed ~~this transaction~~at closing with ~~$120.0 million of~~ borrowings under our revolving credit ~~agreement, along~~facility. Atlantic Energy owns and operates a marine import terminal with ~~the issuance~~20 million gallons of common units through a private placement with certain institutional investors and cash on hand. In August 2007, we issued 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100.0 millionabove ground storage in the ~~aggregate.~~Port of Chesapeake, Virginia. The ~~proceeds from this private placement were used to purchase high-grade securities to fully secure~~assets serve as a supply point for propane customers in the mid-atlantic region, and will extend our ~~term loan borrowings. These units were registered with~~existing northeastern U.S. wholesale propane business into the ~~SEC in January 2008.~~

mid-atlantic. The ~~transfer~~results of the ~~MEG subsidiaries between DCP Midstream, LLC and us represents a transfer between entities under common control. Transfers between entities under common control~~Atlantic Energy acquisition are accounted for at DCP Midstream, LLC’s carrying value, similar to the pooling method. DCP Midstream, LLC recorded its acquisition of the MEG subsidiaries under the purchase method of accounting, whereby the assets and liabilities were recorded at their respective fair values as ofincluded prospectively from the date of ~~the~~ acquisition ~~and we recorded goodwill of approximately $52.8 million, including purchase price adjustments of $1.9 million during the first quarter of~~

~~117~~

in our Wholesale Propane Logistics segment.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

~~2008.~~

The ~~goodwill amount recognized relates primarily~~purchase price allocation is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to ~~projected growth in~~evaluate the ~~Piceance basin due~~initial purchase price allocation, which may be adjusted as additional information relative to ~~significant natural gas reserves~~the fair value of assets and ~~high levels of drilling activity.~~liabilities becomes available. The preliminary purchase price allocation is as follows:

(Millions)

Cash consideration $ 153.8
Payable to DCP Midstream, LLC 10.9
Common limited partner units 12.0

Aggregate consideration $ 176.7

The purchase price allocation is as follows:
Cash $ 11.8
Accounts receivable 14.1
Other assets 1.5
Property, plant and equipment 127.8
Goodwill 52.8
Intangible assets 15.5
Accounts payable (11.1 )
Other liabilities (12.9 )
Non-controlling interest in joint venture (22.8 )

Total purchase price allocation $ 176.7


	(Millions)
Aggregate consideration	$	68.2

Cash	$	0.4
Accounts receivable		2.1
Inventory		16.6
Property, plant and equipment		15.2
Intangible assets		27.2
Goodwill		7.6
Other liabilities		(0.9	)

Total preliminary purchase price allocation	$	68.2

On July ~~1, 2007,~~27, 2010, we acquired ~~a 25% limited liability company~~an additional 5% interest in East Texas, a 40% limited liability company interest in Discovery and the Swap from DCP Midstream, LLC, for aggregate consideration of approximately $271.3 million, consisting of approximately $243.7 million in cash, including net working capital of $1.3 million and other adjustments, the issuance of 620,404 common units to DCP Midstream, LLC valued at $27.0 million and the issuance of 12,661 general partner equivalent units valued at $0.6 million. We financed the cash portion of this transaction with borrowings of $245.9 million under our credit facility. The $118.0 million excess purchase price over the historical basis of the net acquired assets was recorded as a reduction to partners’ equity, and the $27.6 million of common and general partner equivalent units issued as partial consideration for this transaction was recorded as an increase to partners’ equity.

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

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

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

~~Wholesale Propane Logistics Business~~

~~On November 1, 2006, we acquired our wholesale propane logistics business~~Black Lake from DCP Midstream, LLC, in a transaction among entities under common control, for ~~aggregate consideration of approximately $82.9 million, which consisted of $77.3~~$1.5 million in cash, ~~($9.9 million~~financed at closing with borrowings under our revolving credit facility. This transaction brought our ownership interest in Black Lake to 50%. The historical carrying value of ~~which~~DCP Midstream, LLC’s 5% interest in Black Lake was ~~paid in January 2007), and~~$0.7 million; accordingly we have recorded the issuance of 200,312 Class C units valued at approximately $5.6 million. Included in the aggregate consideration was $10.5 million of costs incurred through October 31, 2006, which were associated with the construction of a new pipeline terminal. The $26.3$0.8 million excess purchase price over acquired assets as a decrease in common unitholders equity.

On July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, for $15.1 million in cash, financed at closing with borrowings under our revolving credit facility, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we have remeasured our initial 50% interest in Black Lake to its fair value. Accordingly we recognized a gain of $9.1 million in step acquisition — equity interest re-measurement gain in our consolidated statement of operations for the year ended December 31, 2010, which reflects the increase from the net assets historical ~~basis~~carrying value, to the net assets fair value for our initial 50% interest. We have evaluated certain pre-acquisition contingencies arising from potential environmental issues that existed as of

~~118~~

the acquisition date. We have determined that certain of these pre-acquisition contingencies are probable in nature and estimable as of the acquisition date and, accordingly, have recorded $0.9 million for these contingencies as a part of the purchase price allocation for Black Lake.

The results of our additional 50% interest in Black Lake are included prospectively from the date of acquisition in our NGL Logistics segment. Our calculation of the step acquisition — equity interest re-measurement gain is as follows:


	(Millions)
Fair value of 50% equity interest in Black Lake	$	15.1
Less: Carrying value of 50% equity interest in Black Lake		6.0

Step acquisition — equity interest re-measurement gain	$	9.1

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

The purchase price is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of assets and liabilities becomes available. The preliminary purchase price allocation is as follows:


	(Millions)
Cash consideration	$	15.1

Cash	$	0.8
Accounts receivable		0.6
Property, plant and equipment		27.4
Intangible assets		2.7
Other asset		0.3
Other liabilities		(1.6	)

Fair value of 100% interest in Black Lake		30.2
Less:
Carrying value of initial 50% equity interest in Black Lake		(6.0	)
Step acquisition — equity interest re-measurement gain		(9.1	)

Total preliminary purchase price allocation	$	15.1

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 if Delta meets certain throughput volume thresholds by June 30, 2011, pursuant to a gathering agreement. We recognized the fair value of this contingent consideration of approximately $1.0 million, which we recorded to other current liabilities in our 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 September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0, and there has been no change to our assessment of the fair value as of December 31, 2010. Accordingly, we recognized $1.0 million in other income in our consolidated results of operations during the year ended December 31, 2010.

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 at closing 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.

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

Combined Financial Information

The following tables present the total operating revenues and net income attributable to partners, associated with the acquisition of the Wattenberg pipeline, Atlantic Energy, and an additional 50% interest in Black Lake, or the acquired assets, ~~was recorded as a reduction to partners’ equity, and~~from their respective dates of acquisition through December 31, 2010. These amounts have been included in the ~~$5.6 million~~consolidated statement of ~~common and general partner equivalent units issued as partial consideration for this transaction was recorded as an increase to partners’ equity.~~

~~Combined Financial Information~~

operations.


	Year Ended December 31, 2010
	Wattenberg Pipeline		Atlantic Energy		Additional 50% interest in Black Lake		Total
	(Millions)
Total operating revenues	$	3.3	$	35.5	$	2.9	$	41.7
Net income attributable to partners	$	1.1	$	1.3	$	1.0	$	3.4

The following ~~table presents~~tables present unaudited pro forma information for the consolidated statements of operations for the years ended ~~2008~~December 31, 2010 and ~~2007,~~2009, as if the ~~acquisition of MPP~~acquisitions had occurred at the beginning of each ~~year~~period presented. ~~There is no impact shown~~The 2010 results presented for Wattenberg, Atlantic Energy and Black Lake below represent results of operations from the ~~MEG~~beginning of the period to the respective date of acquisition. The results of operations for these acquired assets subsequent to the date of acquisition ~~because there were no predecessor operations of MEG at~~are included in the DCP Midstream ~~LLC.~~

2008 2007
DCP
DCP

DCP
Midstream
DCP
Midstream

Midstream
Acquisition
Partners, LP
Midstream
Acquisition
Partners, LP

Partners, LP of MPP Pro Forma Partners, LP of MPP Pro Forma
(Millions, except per unit amounts)

Total operating revenues $ 1,285.8 $ 14.8 $ 1,300.6 $ 873.3 $ 20.9 $ 894.2
Net income (loss) $ 125.7 $ 2.2 $ 127.9 $ (15.8 ) $ 1.2 $ (14.6 )
Less:
Net income attributable to predecessor operations — — — (3.6 ) — (3.6 )
General partner interest in net income (11.9 ) — (11.9 ) (2.2 ) (0.1 ) (2.3 )

Net income (loss) allocable to limited partners $ 113.8 $ 2.2 $ 116.0 $ (21.6 ) $ 1.1 $ (20.5 )

Net income (loss) per limited partner unit — basic and diluted $ 3.25 $ 0.04 $ 3.29 $ (1.05 ) $ 0.05 $ (1.00 )

Partners, LP results.


	Year Ended December 31, 2010
	DCP Midstream Partners, LP			Acquisition of the Wattenberg Pipeline		Acquisition of Atlantic Energy		Acquisition of an additional 50% interest in Black Lake		DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	1,269.5		$	0.2	$	64.5	$	4.1	$	1,338.3
Net income attributable to partners	$	48.0		$	0.1	$	1.1	$	0.6	$	49.8
Less:
General partner’s interest in net income or net loss		(16.9	)		—		—		—		(16.9	)

Net income allocable to limited partners	$	31.1		$	0.1	$	1.1	$	0.6	$	32.9

Net income per limited partner unit – basic and diluted	$	0.86		$	—	$	0.03	$	0.02	$	0.91


	Year Ended December 31, 2009
	DCP Midstream Partners, LP			Acquisition of the Wattenberg Pipeline(a)			Acquisition of Atlantic Energy		Acquisition of an additional 50% interest in Black Lake		DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	942.4		$	9.2		$	67.5	$	7.0	$	1,026.1
Net (loss) income attributable to partners	$	(19.1	)	$	(67.0	)	$	0.7	$	1.7	$	(83.7	)
Less:
Net loss attributable to predecessor operations		1.0			—			—		—		1.0
General partner’s interest in net income or net loss		(12.7	)		(0.7	)		—		—		(13.4	)

Net (loss) income allocable to limited partners	$	(30.8	)	$	(67.7	)	$	0.7	$	1.7	$	(96.1	)

Net (loss) income per limited partner unit – basic and diluted	$	(0.99	)	$	(2.16	)	$	0.02	$	0.05	$	(3.08	)

(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 that had recently been put

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2010, 2009 and 2008 — (Continued)

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 ~~companies~~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.

5.
5.	Agreements and Transactions with Affiliates

DCP Midstream, LLC

~~DCP Midstream, LLC provided centralized corporate functions on behalf of our predecessor operations, including legal, accounting, cash management, insurance administration~~

Omnibus Agreement and ~~claims processing, risk management, health, safety~~Other General and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The predecessor’s share of those costs was allocated based on the predecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investments, and intangible assets, net) as compared to DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used were reasonable and resulted in an allocation to the predecessors of their respective costs of doing business, which were borne by DCP Midstream, LLC.

~~Omnibus Agreement~~Administrative Charges

We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC.

Following is a summary of the fees we incurred under the Omnibus Agreement as well as other fees paid to DCP Midstream, LLC:

   Year Ended December 31,
   2010    2009    2008
   (Millions)
Omnibus Agreement
   $ 9.9       $ 9.7       $ 9.8
Other fees — DCP Midstream, LLC
   9.3       10.4       10.4

Total — DCP Midstream, LLC
   $ 19.2       $ 20.1       $ 20.2

Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair

~~119~~

~~DCP MIDSTREAM PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. ~~Under~~
In January 2011, we extended the ~~Omnibus Agreement, DCP Midstream, LLC provided parental guarantees, totaling $43.0 million at~~omnibus agreement through December 31, ~~2008, to certain counterparties to our commodity derivative instruments.~~

~~All of the fees under the Omnibus Agreement are subject to adjustment annually~~2011 for ~~changes in the Consumer Price Index.~~

$10.2 million. The Omnibus Agreement also addresses the following matters:
DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; and
DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts.
• ~~DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;~~
• DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements were in effect as of the closing of our initial public offering in December 2005, until the earlier to occur of the fifth anniversary of the closing of our initial public offering or such time as we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and
• DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts.
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions, will be terminable by DCP Midstream, LLC at its option if the general partner is removed without cause and units held by the general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of us, the general partner (DCP Midstream GP, LP) or the General Partner (DCP Midstream GP, LLC).
~~Following is a summary of the fees we incurred under the Omnibus Agreement~~
East Texas incurs general and ~~the effective date for these fees, as well as other fees paid to~~administrative expenses directly from DCP Midstream, ~~LLC:~~

Year Ended December 31,
Terms

Effective Date
2008 2007 2006
(Millions)

Annual fee 2006 $ 5.1 $ 5.0 $ 4.8
Wholesale propane logistics business November 2006 2.0 2.0 0.3
Southern Oklahoma May 2007 0.2 0.1 —
Discovery July 2007 0.2 0.1 —
Additional services August 2007 0.6 0.2 —
Momentum Energy Group, Inc. August 2007 1.6 0.5 —
Michigan Pipeline & Processing, LLC October 2008 0.1 — —

Total Omnibus Agreement 9.8 7.9 5.1
Other fees 1.8 2.1 3.0

Total $ 11.6 $ 10.0 $ 8.1

~~120~~

LLC. During the years ended December 31, 2010, 2009 and 2008, East Texas incurred $7.8 million, $8.5 million and $8.6 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
In addition to the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC, which includes expenses for our predecessor operations, of $1.5 million, $1.9 million and $1.8 million, respectively, for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.
Competition
None of DCP Midstream, LLC, ~~nor~~or any of its affiliates, including Spectra Energy and ConocoPhillips, is restricted, under either the partnership agreement or the Omnibus Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Spectra Energy and ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification
The Black Lake pipeline has experienced increased operating costs due to pipeline integrity testing that commenced in 2005 and was completed during the second quarter of 2008. Testing revealed irregularities, the more severe of which were repaired in October 2008 and the less severe of which are scheduled for repair in 2009. DCP Midstream, LLC agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions associated with repairing the Black Lake pipeline that are determined to be necessary as a result of the pipeline integrity testing. We anticipate repairs of approximately $0.8 million on the pipeline, which will be funded directly from Black Lake. We will not make contributions to Black Lake to cover these expenses.
In connection with our acquisition of our wholesale propane logistics business, DCP Midstream, LLC ~~agreed to indemnify us until October 31, 2009 for any claims for fines or penalties of any governmental authority for periods prior to the closing,~~ agreed to indemnify us until October 31, 2010 if certain contractual matters result in a claim, and agreed to indemnify us indefinitely for breaches of the agreement. The indemnity obligation for breach of the representations and warranties is not effective until claims exceed in the aggregate $680,000 and is subject to a maximum liability of $6.8 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisitions of East Texas and Discovery from DCP Midstream, LLC, DCP Midstream, LLC agreed to indemnify us until July 1, 2009 for any claims for fines or penalties of any governmental authority for periods prior to the closing and that are associated with certain East Texas assets that were formerly owned by Gulf South and UP Fuels, and agreed to indemnify us indefinitely for breaches of the agreement and certain existing claims. The indemnity obligation for breach of the representations and warranties is not effective until claims exceed in the aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisition of certain subsidiaries of MEG, DCP Midstream, LLC agreed to indemnify us until August 29, 2008 for any breach of the representations and warranties (except certain corporate related matters that survive indefinitely), and indefinitely for breaches of the agreement.
We have not pursued indemnification under ~~these agreements.~~
this agreement.
Other Agreements and Transactions with DCP Midstream, LLC
On November 4, 2010, we entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in Southeast Texas, for $150.0 million. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines, three natural gas processing plants with recently increased processing capacity totaling 380 MMcf/d, and natural gas storage assets with 9 Bcf of existing storage capacity. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. This transaction closed on January 1, 2011.
On September 16, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $6.2 million, for net proceeds of $3.6 million. The surplus equipment is the result of a consolidation of operations at our Anderson Gulch plant in the Piceance Basin. The net proceeds of $3.6 million have been distributed 75% to us and 25% to the noncontrolling interest in Collbran, based upon proportionate ownership. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of December 31, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our consolidated balance sheets. In addition, we have recorded a deferred credit of $3.6 million in other current liabilities in our consolidated balance sheets.
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. We have recognized a contribution of $0.6 million for the year ended December 31, 2010, from DCP Midstream, LLC in our consolidated statements of changes in equity representing the difference between the net book value and the proceeds received for the surplus equipment.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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 certain capital projects which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $13.8 million and $67.5 million for the years ended December 31, 2010 and 2009, respectively.
On February 11, 2009, our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, was temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. We are actively pursuing full reimbursement of our costs and lost margin associated with the incident from the responsible third party. 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 25% of any claims received as reimbursement of costs and lost margin, from the responsible third party or from insurance. DCP Midstream, LLC will pay 75% of costs related to the incident as a result of this agreement.
On February 25, 2009, we entered into a Contribution Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC contributed an additional 25.1% interest in East Texas and the NGL Hedge to us in exchange for 3,500,000 Class D units, providing us with a 50.1% interest in East Texas. This transaction closed in April 2009. Subsequent to this transaction we consolidate our 50.1% interest in East Texas and consequently no longer account for East Texas as an unconsolidated affiliate. The Class D Units converted into the Partnership’s Common Units on a one-for-one basis on August 17, 2009.
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 ~~the inlet of the Pelico system,~~us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. ~~Because of~~We purchase natural gas from DCP Midstream, ~~LLC’s~~

~~121~~
LLC upstream of Pelico and transport it to Pelico under a firm transportation agreement with an affiliate. Our purchases from DCP ~~MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~ability~~Midstream, LLC are at DCP Midstream LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand are sold to ~~move~~DCP Midstream, LLC at an index-based price, less contractually agreed to marketing fees. Revenues associated with these activities are reported gross in our consolidated statements of operations as sales of natural gas, ~~around Pelico, there are certain contractual relationships around Pelico that define how natural gas is bought~~propane, NGLs and ~~sold between us and DCP Midstream, LLC. The agreement is described below:~~
• DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. We generally report purchases associated with these activities gross in the consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates.
• If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index-based price, less a contractually agreed-to marketing fee. We generally report revenues associated with these activities gross in the consolidated statements of operations as sales of natural gas, propane and NGLs to affiliates.
• In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC, plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential, plus a fixed fuel charge and other related adjustments. We generally report revenues and purchases associated with these activities net in the consolidated statements of operations as transportation, processing and other services to affiliates.
condensate to affiliates.
In addition, in our Natural Gas Services segment, we sell NGLs processed at certain of our ~~Minden and Ada~~ plants, and sell condensate removed from the gas gathering systems that deliver to ~~the Minden and Ada plants, and from~~certain of our ~~Pelico system~~systems under contracts to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for transportation, processing and other charges from the tailgate of the respective ~~asset,~~asset.
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 ~~recorded~~part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from the Southern Oklahoma system being processed at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the consolidated statements of operations as ~~sales~~purchases of natural gas, propane, NGLs and condensate tofrom affiliates. ~~We also sell propane to a subsidiary~~In addition,
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
as part of this arrangement, DCP Midstream, ~~LLC.~~
LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other 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 ~~pipeline,~~and Wilbreeze pipelines, pursuant to a fee-based ~~rate~~rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the ~~Seabreeze pipeline under a~~ transportation ~~agreement.~~agreements. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other ~~services~~ to affiliates.
In ~~December 2006, we completed construction~~conjunction with our acquisition of the Wattenberg pipeline, which is part of our ~~Wilbreeze pipeline, which connects~~NGL Logistics segment, we signed a ~~DCP Midstream, LLC gas processing plant to our Seabreeze pipeline. The project is supported by an NGL product dedication~~transportation agreement with DCP Midstream, ~~LLC.~~LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement was effective through December 31, 2010. Effective January 1, 2011, we entered into a 10-year dedication and transportation agreement with a subsidiary of DCP Midstream, LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are dedicated for transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff. We generally report revenues ~~which are earned pursuant to a fee-based rate applied to the volumes transported on this pipeline,~~associated with these activities in the consolidated statements of operations as transportation, processing and other ~~services~~ to affiliates.
~~We anticipate continuing to purchase commodities from and sell commodities to~~
DCP Midstream, LLC has issued parental guarantees totaling $65.0 million as of December 31, 2010, in ~~the ordinary course~~favor of ~~business.~~
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 these outstanding guarantees.
In conjunction with our acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for certain Discovery capital projects, which were forecasted to be completed prior to our acquisition of a 40% limited liability company interest in Discovery. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $0.7 million and $3.8 million during the years ended December 31, 2009 and ~~$0.3 million during~~ 2008, ~~and 2007,~~ respectively to reimburse us for these capital projects, which were substantially completed during 2008. There were no reimbursements to us in ~~2008.~~
~~In the second quarter of 2006, we entered into a letter agreement with~~ 2010.
DCP Midstream, LLC ~~whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for capital projects, which were~~

~~122~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
forecasted to be completed prior to our initial public offering, but were not completed by that date. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $3.4 million during 2006 and $0.3 million during 2007, to reimburse us for the capital costs we incurred, primarily for growth capital projects.
~~In July 2008, DCP Midstream, LLC~~has issued ~~additional~~ parental guarantees ~~outside of the Omnibus Agreement,~~for its 49.9% limited liability company interest in East Texas, totaling $200.0 million, to certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. These guarantees were reduced to $65.0$6.0 million as of December 31, ~~2008~~2010, in favor of certain counterparties to ~~correspond with lower commodity prices~~processing and ~~collateral requirements. We pay DCP Midstream, LLC interest of 0.5% per annum on these outstanding guarantees.~~
transportation agreements at East Texas. Concurrently, we have issued similar guarantees for our 50.1% interest.
DCP Midstream, LLC was a significant customer during the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~
~~Duke Energy~~
~~Prior to December 31, 2006, we purchased natural gas from Duke Energy and its affiliates.~~
2008.
Spectra Energy
We purchase a portion of our propane from and market propane on behalf of Spectra Energy. We anticipate continuing to purchase propane from and market propane on behalf of Spectra Energy in the ordinary course of business.
~~During the second quarter of 2008, we entered into~~have a propane supply agreement with Spectra ~~Energy. This agreement,~~Energy, effective from May 1, 2008 ~~and terminating~~through April 30, ~~2014,~~2012, which provides us propane supply at our Providence marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. ~~This contract replaces~~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 ~~under~~us with a cash payment of $3.0 million, which we recognized in other income — affiliates, in our Wholesale Propane Logistics segment in the consolidated statements of operations.
In conjunction with our acquisition of Atlantic Energy on July 30, 2010, we acquired a propane supply agreement with Spectra Energy, effective from May 1, 2010 to April 30, 2012, which provides us propane supply for our Chesapeake marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 65 million gallons of propane annually.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
In December 2010, Spectra Energy’s international propane supplier breached its contract with Spectra Energy by failing to make certain scheduled propane deliveries that were to be delivered to us under our propane supply contracts with Spectra Energy. We were able to secure spot shipments on the open market at a ~~third party that was terminated~~price higher than our contract price to cover these missing deliveries. In December 2010 Spectra Energy made a $17.0 million payment to us to reimburse us for ~~non-performance during~~ the ~~first quarter of 2008.~~
damages we incurred for our open market purchases.
ConocoPhillips
We have multiple agreements ~~whereby we provide a variety of services to~~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 ~~$1.9~~$0.2 million, ~~$2.9~~$0.6 million and ~~$3.9~~$1.9 million of capital reimbursements during the years ended December 31, 2010, 2009 and 2008, ~~2007 and 2006,~~ respectively.

~~123~~
Summary of Transactions with Affiliates
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
The following table summarizes the transactions with affiliates:

Year Ended December 31,
2008 2007 2006
(Millions)

DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate $ 475.7 $ 290.0 $ 231.7
Transportation, processing and other $ 15.4 $ 6.0 $ 4.8
Purchases of natural gas, propane and NGLs $ 175.3 $ 150.1 $ 102.9
(Losses) gains from derivative activity, net $ (3.1 ) $ (4.5 ) $ 0.1
Operating and maintenance expense $ — $ 0.4 $ 0.2
General and administrative expense $ 11.6 $ 10.0 $ 8.1
Interest expense $ 0.4 $ — $ —
Spectra Energy:
Sales of natural gas, propane, NGLs and condensate $ 0.3 $ 1.1 $ —
Transportation, processing and other $ 0.2 $ — $ —
Purchases of natural gas, propane and NGLs $ 51.0 $ — $ —
Duke Energy:
Purchases of natural gas, propane and NGLs $ — $ — $ 3.4
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate $ 1.8 $ 6.6 $ 1.1
Transportation, processing and other $ 10.4 $ 10.6 $ 8.0
Purchases of natural gas, propane and NGLs $ 36.6 $ 29.2 $ 12.9
~~We had accounts receivable and accounts payable with affiliates as follows:~~

December 31,
2008 2007
(Millions)

DCP Midstream, LLC:
Accounts receivable $ 30.3 $ 47.3
Accounts payable $ 27.9 $ 53.3
Spectra Energy:
Accounts receivable $ 4.0 $ 1.5
Accounts payable $ 5.3 $ —
ConocoPhillips:
Accounts receivable $ 2.5 $ 3.3
Accounts payable $ 0.4 $ 2.3
~~The following summarizes the unrealized losses on derivative instruments with affiliates:~~

December 31,
2008 2007
(Millions)

DCP Midstream, LLC:
Unrealized losses — current $ (1.2 ) $ (2.7 )

~~124~~
   Year Ended December 31,
   2010 2009 2008
   (Millions)
DCP Midstream, LLC:

Sales of natural gas, propane, NGLs and condensate
   $ 522.7    $ 451.4    $ 760.1
Transportation, processing and other
   $ 12.1    $ 7.5    $ 15.4
Purchases of natural gas, propane and NGLs
   $ 183.1    $ 138.4    $ 175.4
Losses from commodity derivative activity, net
   $ (1.2 ) $ (3.5 ) $ (3.7 )
General and administrative expense
   $ 19.2    $ 20.1    $ 20.2
Interest expense
   $ 0.2    $ 0.2    $ 0.4
Spectra Energy:

Sales of natural gas, propane, NGLs and condensate
   $ —    $ —    $ 0.3
Transportation, processing and other
   $ 0.2    $ 0.3    $ 0.2
Purchases of natural gas, propane and NGLs (a)
   $ 82.1    $ 95.2    $ 50.9
Other income
   $ 3.0    $ —    $ —
ConocoPhillips:

Sales of natural gas, propane, NGLs and condensate
   $ 5.7    $ 5.3    $ 31.1
Transportation, processing and other
   $ 8.1    $ 8.2    $ 10.6
Purchases of natural gas, propane and NGLs
   $ 7.4    $ 12.7    $ 36.7
General and administrative expense
   $ 0.2    $ 0.3    $ —
Unconsolidated affiliates:

Purchases of natural gas, propane and NGLs
   $ 4.8    $ 0.4    $ —
(a) Includes a $17.0 million payment received in December 2010 for reimbursement of damages we incurred when an international propane supplier breached its contract with Spectra Energy.
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
We had balances with affiliates as follows:
   December 31,
   2010 2009
   (Millions)
DCP Midstream, LLC:

Accounts receivable
   $ 60.1    $ 71.5
Accounts payable
   $ 27.0    $ 24.4
Unrealized gains on derivative instruments—current
   $ 1.3    $ 5.5
Unrealized losses on derivative instruments—current
   $ (1.8 ) $ (5.4 )
Spectra Energy:

Accounts receivable
   $ —    $ 0.1
Accounts payable
   $ 8.7    $ 16.6
ConocoPhillips:

Accounts receivable
   $ 1.6    $ 2.2
Accounts payable
   $ 1.0    $ 2.1
Unconsolidated affiliates:

Accounts payable
   $ 0.9    $ —
6.
6.   Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:

Depreciable
December 31,
Life 2008 2007
(Millions)

Gathering systems 15 — 30 Years $ 405.0 $ 371.3
Processing plants 25 — 30 Years 163.4 91.4
Terminals 25 — 30 Years 28.5 24.2
Transportation 25 — 30 Years 174.0 141.0
General plant 3 — 5 Years 6.0 4.0
Construction work in progress 43.5 25.5

Property, plant and equipment 820.4 657.4
Accumulated depreciation (191.1 ) (156.7 )

Property, plant and equipment, net $ 629.3 $ 500.7

~~The above amounts include accrued capital expenditures~~
   Depreciable
Life    December 31,
      2010 2009
      (Millions)
Gathering and transmission systems
   15 —30 Years       $ 992.0    $ 900.2
Processing, storage and terminal facilities
   20 —50 Years       585.2    456.4
Other
   3 — 30 Years       12.6    15.2
Construction work in progress
      42.1    21.8

Property, plant and equipment
      1,631.9    1,393.6
Accumulated depreciation
      (462.8 ) (393.5 )

Property, plant and equipment, net
      $ 1,169.1    $ 1,000.1

During the year ended December 31, 2010, we re-assessed our major classes of ~~$12.3~~property, plant and equipment and changed our presentation.
Interest capitalized on construction projects in 2010, 2009 and 2008, was $0.2 million, $1.3 million and ~~$8.4~~$0.3 million, ~~as of December 31, 2008 and 2007, respectively, which are included in other current liabilities in the consolidated balance sheets.~~
respectively.
Depreciation expense was ~~$34.4~~$70.0 million, ~~$23.3~~$62.3 million and ~~$12.4~~$51.1 million for the years ended December 31, 2010, 2009 and 2008, ~~2007 and 2006,~~ respectively.
We lease one of our Michigan transmission pipelines to a third party under a long-term contract. The carrying value of the pipeline is approximately $23.0 million, with accumulated depreciation of $0.2 million. Minimum future non-cancelable rental payments are as follows:

Rental Payments
(Millions)

2009 $ 3.0
2010 2.9
2011 2.9
2012 2.8
2013 2.3
Thereafter 20.7

Total $ 34.6

Asset Retirement Obligations— ~~Our~~As of December 31, 2010, we had asset retirement obligations ~~relate primarily to the retirement~~ of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation,$10.8 million included in other long-term liabilities in the consolidated balance ~~sheets, was $7.9 million and $3.1 million at~~sheets. As of December 31, ~~2008 and 2007, respectively. The~~2009 we had asset retirement ~~obligation increased~~obligations of $8.5 million included in ~~2008 and 2007, respectively, as a result of~~other long-term liabilities in the ~~MPP and MEG acquisitions.~~consolidated balance sheets. Accretion expense for the years ended December 31, 2010, 2009 and 2008 was $0.6 million, $0.3 million and ~~2007 was~~ $0.4 million, ~~and $0.1 million, respectively, and for the year ended December 31, 2006 was not significant.~~
respectively.
We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines,

~~125~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.
7.
7.   Goodwill and Intangible Assets
The change in the carrying amount of goodwill is as follows:

December 31,

2008
2007
(Millions)

Beginning of period $ 80.2 $ 29.3
Acquisitions 8.6 50.9

End of period $ 88.8 $ 80.2

   December 31,
   2010    2009
   (Millions)
Beginning of period
   $ 92.1       $ 88.8
Acquisitions
   7.6       3.3

End of period
   $ 99.7       $ 92.1

Goodwill increased ~~during 2008~~in 2010 by ~~$6.7~~$7.6 million as a result of the MPP acquisition, and by $1.9 million for the final purchase price allocation for the MEG subsidiaries acquired from DCP Midstream, LLC. The increase in goodwill during 2007 represents the amount that we recognized in connection with our acquisition of ~~the MEG subsidiaries from DCP Midstream, LLC.~~
We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Atlantic Energy.
Our annual goodwill impairment tests indicated that our reporting unit’s fair value exceeded its carrying or book ~~value.~~
During the fourth quarter of 2008, as a result of the decline in the general equity market indices and in our unit price on the New York Stock exchange, we updated our fair value analysis using current marketplace assumptions and concluded that the carrying value of goodwill is recoverable;value; therefore, we did not record any impairment charges during the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006. However, given the current volatility~~2008.
The carrying value of goodwill as of December 31, 2010 and 2009 was $36.9 million and $29.3 million, respectively, for our Wholesale Propane Logistics segment and was $62.8 million as of both periods for our Natural Gas Services segment.
If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the ~~equity market, as well as volatile commodity prices, we will continue to monitor~~period in which the ~~recoverability of such amounts. Continued volatility and marketplace activity may alter our conclusion in the future, and could result in the recognition of an impairment charge.~~
carrying value exceeds fair value.
Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

December 31,

2008
2007
(Millions)

Gross carrying amount $ 52.5 $ 32.4
Accumulated amortization (4.8 ) (2.7 )

Intangible assets, net $ 47.7 $ 29.7

~~126~~
   December 31,
   2010 2009
   (Millions)
Gross carrying amount
   $ 96.4    $ 66.2
Accumulated amortization
   (9.4 ) (5.7 )

Intangible assets, net
   $ 87.0    $ 60.5

~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Intangible assets increased in ~~2008~~2010 by $27.2 million as a result of ~~the MPP acquisition.~~
our acquisition of Atlantic Energy and by $2.7 million as a result of our acquisition of an additional 50% interest in Black Lake.
For the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, we recorded amortization expense of ~~$2.1~~$3.7 million, ~~$1.1~~$2.6 million and ~~$0.4~~$2.1 million, respectively. As of December 31, ~~2008,~~2010, the remaining amortization periods ~~range~~ranged from approximately ~~less than one year~~11 years to 25 years, with a weighted-average remaining period of approximately 21 years.
The weighted-average remaining amortization for the $27.2 million of intangible assets acquired with our acquisition of Atlantic Energy on July 30, 2010 is 25 years, and for the $2.7 million of intangible assets acquired with our acquisition of an additional 50% interest in Black Lake on July 30, 2010 is 20 years.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Estimated future amortization for these intangible assets is as follows:

Estimated Future

Amortization
(Millions)

2009 $ 2.6
2010 2.6
2011 2.3
2012 2.3
2013 2.3
Thereafter 35.6

Total $ 47.7

Estimated Future Amortization

(Millions)
2011
   $ 4.4
2012
   4.4
2013
   4.4
2014
   4.4
2015
   4.4
Thereafter
   65.0

Total
   $ 87.0

8.
8.  Investments in Unconsolidated Affiliates ~~Equity Method Investments~~
The following table summarizes our ~~equity method investments:~~

Percentage of

Ownership as of
Carrying Value as of

December 31,
December 31,
2008 and 2007 2008 2007
(Millions)

Discovery Producer Services LLC 40 % $ 105.0 $ 117.9
DCP East Texas Holdings, LLC 25 % 63.9 62.9
Black Lake Pipe Line Company 45 % 6.3 6.2
Other 50 % 0.2 0.2

Total equity method investments $ 175.4 $ 187.2

~~Discovery operates a600 MMcf/d~~ ~~cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana, a natural gas pipeline from offshore deep water~~investments in ~~the Gulf of Mexico that transports gas to its processing plant in Larose, Louisiana with a design capacity of600 MMcf/d~~ ~~and approximately 280 miles of pipe, and several laterals in the Gulf of Mexico.~~ unconsolidated affiliates:
   Percentage of
Ownership as of
December 31,
2010 and 2009    Carrying Value as of
December 31,
      2010    2009
      (Millions)
Discovery Producer Services, LLC
   40%       $ 104.1       $ 108.2
Black Lake Pipe Line Company(a)
   100% and 45%       —       6.2
Other
   50%       0.2       0.2

Total investments in unconsolidated affiliates
      $ 104.3       $ 114.6

(a) On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of ~~$39.7~~$35.1 million and ~~$43.7~~$37.6 million at December 31, ~~2008~~2010 and ~~2007,~~2009, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.
East Texas is engaged in the business of gathering, transporting, treating, compressing, processing, and fractionating natural gas and NGLs. Its operations, located near Carthage, Texas, include a natural gas processing complex with a total capacity of~~780 MMcf/d~~ ~~and a natural gas liquids fractionator. The facility is connected to an approximately900-mile~~ gathering system, as well as third party gathering systems. The complex includes and is adjacent to the Carthage Hub, which delivers residue gas to interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 Bcf/d, acts as a key exchange point for the purchase and sale of residue gas.

~~127~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~Black Lake owns a317-mile~~ ~~NGL pipeline, with a throughput capacity of approximately 40 MBbls/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas.~~ There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of ~~$6.0 million and $6.4~~$5.7 million at December 31, ~~2008 and 2007, respectively,~~2009, which iswas associated with, and iswas being accreted over, the life of the underlying long-lived assets of Black Lake.
Earnings from ~~equity method~~ investments in unconsolidated affiliates were as follows:

Year Ended December 31,
2008 2007 2006
(Millions)

Discovery Producer Services LLC $ 17.4 $ 24.1 $ 16.9
DCP East Texas Holdings, LLC 16.1 14.6 12.0
Black Lake Pipe Line Company and other 0.8 0.6 0.3

Total earnings from equity method investments $ 34.3 $ 39.3 $ 29.2

Distributions from equity method investments $ 59.9 $ 38.9 $ 25.9

Earnings from equity method investments, net of distributions $ (25.6 ) $ 0.4 $ 3.3

   Year Ended December 31,
   2010    2009    2008
   (Millions)
Discovery Producer Services LLC
   $ 23.0       $ 16.6       $ 17.4
Black Lake Pipe Line Company and other(a)
   0.8       1.9       0.8

Total earnings from unconsolidated affiliates
   $ 23.8       $ 18.5       $ 18.2

(a)
On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
The following summarizes combined financial information of our ~~equity method investments:~~

Year Ended December 31,
2008 2007 2006
(Millions)

Statements of operations:
Operating revenue $ 792.7 $ 739.6 $ 686.9
Operating expenses $ (696.9 ) $ 634.6 $ 612.2
Net income $ 99.8 $ 106.8 $ 77.4

December 31,
2008 2007
(Millions)

Balance sheet:
Current assets $ 104.3 $ 168.8
Long-term assets 646.3 630.3
Current liabilities (84.4 ) (100.9 )
Long-term liabilities (22.4 ) (14.9 )

Net assets $ 643.8 $ 683.3

investments in unconsolidated affiliates:
   Year Ended December 31,
   2010(a)    2009    2008
   (Millions)
Statements of operations:

Operating revenue
   $ 211.6       $ 168.1       $ 247.9
Operating expenses
   $ 158.9       $ 127.2       $ 216.7
Net income
   $ 52.8       $ 40.4       $ 35.3
(a) Excludes the results of Black Lake from July 30, 2010 to December 31, 2010.
   December 31,
   2010(a) 2009
   (Millions)
Balance sheet:

Current assets
   $ 34.6    $ 41.8
Long-term assets
   356.7    383.8
Current liabilities
   (17.2 ) (17.4 )
Long-term liabilities
   (25.6 ) (23.6 )

Net assets
   $ 348.5    $ 384.6

(a) On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
9. Fair Value Measurement
Determination of Fair Value
Below is a general description of our valuation methodologies for derivative financial assets and liabilities, as well as short-term and restricted investments, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. ~~In the event that~~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

~~128~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of moneyand/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
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
• Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all
derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with ~~us.~~
• Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty,us as well as any letters of credit that wethey 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.
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.~~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 ~~marketplace~~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 1312 Risk Management ~~Activities Credit Risk~~ and ~~Financial Instruments.~~
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.~~
follows:
•
Level 1 — inputs are unadjusted quoted prices foridenticalassets or liabilities in active markets.

~~129~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
•
Level 2 — inputs include quoted prices forsimilarassets 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.~~
Level 3 — inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon the ~~lowest level of~~ input that ~~is significant to~~requires the highest degree of judgment in the determination of the instrument’s fair ~~value measurement.~~value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include ~~over the counter,~~over-the-counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.
Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and aan 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 ~~correlation~~relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.
Interest Rate Derivative Assets and Liabilities
We ~~have~~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, and are held with major financial institutions, which are expected to fully perform under the terms of our agreements.~~debt. The swaps are generally priced based upon a ~~United States Treasury~~London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the ~~United States Treasury~~LIBOR instrument. Given that a ~~significant~~ portion of the swap

~~130~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit ~~our~~and entity valuation ~~as well as liquidity reserves~~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~~were required to post collateral to secure the term loan portion of our credit facility, and ~~may~~could elect to invest a portion of our available cash and restricted investment balances in various financial instruments such as
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
commercial paper and money market ~~instruments and highly rated tax-exempt debt securities that have stated maturities of 20 years or more, which are categorized as available-for-sale securities.~~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 ~~and highly rated tax-exempt debt securities~~ 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 December 31, ~~2008, nearly all~~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 ~~short-term~~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 ~~restricted investments were held in the form~~would generally be classified within Level 3.
We utilize fair value on a recurring basis to measure our contingent consideration that is a result of ~~money market securities. By virtue of our balances in these funds on September 19, 2008, all of these investments~~certain acquisitions. The inputs used to determine such fair value are ~~eligible for,~~primarily based upon internally developed cash flow models and ~~the funds~~ are ~~participating in, the U.S. Treasury Department’s Temporary Guarantee Program for Money Market Funds.~~
classified within Level 3.
The following table presents the financial instruments carried at fair value as of December 31, ~~2008,~~2010 and 2009, by consolidated balance sheet caption and by valuation hierarchy, as described above:

Internal Models
Internal Models

Quoted Market
with Significant
with Significant

Prices in
Observable
Unobservable

Active Markets
Market Inputs
Market Inputs
Total Carrying

(Level 1) (Level 2) (Level 3) Value
(Millions)

Current assets:
Commodity derivative instruments(a) $   — $ 15.1 $ 0.3 $ 15.4
Long-term assets:
Restricted investments $ — $ 60.2 $ — $ 60.2
Commodity derivative instruments(b) $ — $ 6.9 $ 1.7 $ 8.6
Interest rate instruments(b) $ — $ — $ — $ —
Current liabilities(c):
Commodity derivative instruments $ — $ (1.2 ) $ — $ (1.2 )
Interest rate instruments $ — $ (16.5 ) $ — $ (16.5 )
Long-term liabilities(d):
Commodity derivative instruments $ — $ (3.2 ) $ — $ (3.2 )
Interest rate instruments $ — $ (22.8 ) $ — $ (22.8 )
   December 31, 2010 December 31, 2009
   Level 1    Level 2 Level 3 Total
Carrying
Value Level 1    Level 2 Level 3 Total
Carrying
Value
   (Millions)
Current assets:

Short term investments(a)
   $ —       $ —    $ —    $ —    $ —       $ 0.1    $ —    $ 0.1
Commodity derivatives(b)
   $ —       $ 1.6    $ 0.3    $ 1.9    $ —       $ 6.9    $ 0.4    $ 7.3
Long-term assets:

Restricted investments
   $ —       $ —    $ —    $ —    $ —       $ 10.0    $ —    $ 10.0
Commodity derivatives(c)
   $ —       $ 1.1    $ 0.3    $ 1.4    $ —       $ 1.8    $ 0.2    $ 2.0
Current liabilities(d):

Commodity derivatives
   $ —       $ (25.9 ) $ (0.1 ) $ (26.0 ) $ —       $ (20.3 ) $ (0.8 ) $ (21.1 )
Interest rate derivatives
   $ —       $ (17.0 ) $ —    $ (17.0 ) $ —       $ (20.4 ) $ —    $ (20.4 )
Long-term liabilities(e):

Commodity derivatives
   $ —       $ (39.9 ) $ (0.5 ) $ (40.4 ) $ —       $ (46.0 ) $ (0.4 ) $ (46.4 )
Interest rate derivatives
   $ —       $ (9.9 ) $ —    $ (9.9 ) $ —       $ (11.6 ) $ —    $ (11.6 )
(a) Included in other current assets in our consolidated balance sheets.
(b) Included in current unrealized gains on derivative instruments in our consolidated balance sheets.
~~(b)~~ (c) Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.
~~(c)~~ (d) Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
~~(d)~~ (e) Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

~~131~~
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Changes in Level 3 Fair Value Measurements
The ~~table~~tables below ~~illustrates~~illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market,and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers In/Out of Level 3” caption.
We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.

Net Realized

and Unrealized
Net Unrealized

Balance at
Gains Included
Transfers In/
Purchases,
Balance at
Gains (Losses)

December 31,
in (Losses)
Out of
Issuances and
December 31,
Still Held Included

2007 Earnings Level 3(a) Settlements, Net 2008 in Earnings(b)
(Millions)

Commodity derivative instruments:
Current assets $ 0.2 $ 0.8 $ — $ (0.7 ) $ 0.3 $ 0.3
Long-term assets $ 1.5 $ 1.0 $ (0.8 ) $ — $ 1.7 $ 1.0
Current liabilities $ (1.6 ) $ (0.2 ) $ — $ 1.8 $ — $ —
Long-term liabilities $ (0.2 ) $ 0.2 $ — $ — $ — $ 0.2
Commodity Derivative Instruments
Current
Assets Long-Term
Assets Current
Liabilities Long-Term
Liabilities
(Millions)
Year ended December 31, 2010:

Beginning balance
$ 0.4    $ 0.2    $ (0.8 ) $ (0.4 )
Net realized and unrealized gains (losses) included in earnings
2.0    1.3    (0.3 ) (0.1 )
Transfers into Level 3(a)
—    —    —    —
Transfers out of Level 3(a)
—    —    —    —
Purchases, Issuances and Settlements net
(2.1 ) (1.2 ) 1.0    —

Ending balance
$ 0.3    $ 0.3    $ (0.1 ) $ (0.5 )

Net unrealized gains (losses) still held included in earnings(b)
$ 0.3    $ 0.1    $ (0.1 ) $ (0.1 )

Year ended December 31, 2009:

Beginning balance
$ 0.3    $ 1.7    $ —    $ —
Net realized and unrealized gains (losses) included in earnings
0.2    (1.5 ) (3.9 ) (0.4 )
Net transfers (out) of Level 3(c)
(0.1 ) —    —    —
Purchases, Issuances and Settlements net
—    —    3.1    —

Ending balance
$ 0.4    $ 0.2    $ (0.8 ) $ (0.4 )

Net unrealized gains (losses) still held included in earnings(b)
$ 0.4    $ (0.1 ) $ (1.8 ) $ (0.4 )

(a) Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the ~~period and amounts transferred out are reflected at fair value at the beginning of the~~ period.
(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains ~~(losses)~~or losses relating to assets and liabilities classified as Level 3 that are still held atas of December 31, ~~2008.~~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.
During the first quarter of 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
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
approximately $1.0 million, which we recorded to other current liabilities in our consolidated balance sheets. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0, and there has been no change to our assessment of the fair value as of December 31, 2010. Accordingly we recognized $1.0 million in other income in our consolidated results of operations during the year ended December 31, 2010.
During year ended December 31, 2010, we had no significant transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.
10. 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 assumptionsand/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 $398.0 million and $388.9 million as of December 31, 2010 and $613.0 million and $590.0 million, respectively as of December 31, 2009. The carrying and fair values of 3.25% Senior Notes are $250.0 million and $247.0 million as of December 31, 2010. We determine the fair value of ~~long-term debt approximates fair~~our credit facility borrowings based upon the discounted present value asof 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 isswap agreements on a portion of our interest rate exposure which swaps variable ~~and reflects current market conditions.~~

~~132~~
for fixed interest rates.
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
11.
~~11.~~   Debt
Long-term debt was as follows:

Principal Amount

2008
2007
(Millions)

Revolving credit facility, weighed-average interest rate of 2.08% and 5.47%, respectively, due June 21, 2012(a) $ 596.5 $ 530.0
Term loan facility, interest rate 1.54% and 5.05%, respectively, due June 21, 2012(b) 60.0 100.0

Total long-term debt $ 656.5 $ 630.0

December 31,
2010 December 31,
2009
(Millions)
Credit Agreement

Revolving credit facility, weighted-average variable interest rate of 1.14% and 0.69%, respectively, and net effective interest rate of 4.28% and 4.41%, respectively, due June 21, 2012(a)
$ 398.0    $ 603.0
Term loan facility, variable interest rate of 0.34%, due June 21, 2012(b)
—    10.0

Total amounts outstanding under the Credit Agreement
398.0    613.0
Debt Securities

Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015
250.0    —
Unamortized discount
(0.2 ) —

Total long-term debt
$ 647.8    $ 613.0

(a) $~~575.0~~275.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from ~~2.26%~~3.97% to 5.19%, for a net effective rate of ~~4.48%~~4.28% on the ~~$596.5~~$398.0 million of outstanding debt under our revolving credit facility as of December 31, ~~2008.~~2010.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
(b) The term loan facility is fully secured by restricted ~~investments.~~investments as of December 31, 2009. The term loan was repaid during the first quarter of 2010.
Credit Agreement
We have an ~~$824.6~~$850.0 million~~5-year~~ revolving credit ~~agreement~~facility that matures June 21, 2012, or the Credit ~~Agreement, which consists of:~~
• ~~a $764.6 million revolving credit facility; and~~
• ~~a $60.0 million term loan facility.~~
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 the $25.4 million of available capacity to our revolving credit facility.
At December 31, ~~2008~~2010 and ~~2007,~~2009, we had $32.1 million and $0.3 million, ~~and $0.2 million~~respectively, of letters of credit issued and outstanding under the ~~credit agreement~~Credit Agreement. As of December 31, 2009, we had outstanding ~~respectively. Outstanding~~term loan balances under the ~~term loan facility are~~Credit Agreement, which were fully collateralized by investments in high-grade securities ~~which are~~ classified as restricted investments in the accompanying consolidated balance ~~sheet as of December 31, 2008 and 2007.~~sheet. As of December 31, ~~2008,~~2010, the ~~available~~unused capacity under the revolving credit facility was ~~$171.5~~$419.9 million, of which ~~is net of~~ approximately ~~$21.7~~$265.0 million ~~non-participation by Lehman Brothers Commercial Bank, or Lehman Brothers, as discussed below.~~was available for general working capital purposes. We incurred $0.6 million of debt issuance costs ~~during 2007~~ associated with the Credit Agreement. These expenses are deferred as other long-term assets in the consolidated balance sheet and will be amortized over the term of the Credit Agreement.
Our borrowing capacity is limited at December 31, 2010 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.
Under the Credit Agreement, indebtedness under the revolving credit facility bears interest at either: (1) the higher of ~~Wachovia~~Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%; or (2) LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our ~~leverage level or~~ credit rating. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our ~~applicable leverage level or debt~~credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to either: (1) LIBOR plus 0.10%; or (2) the higher of ~~Wachovia~~Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%.
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. ~~The Credit Agreement also requires us~~
Debt Securities
On September 30, 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received proceeds of $247.7 million, which are net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.6 million and $0.2 million, respectively, which we used to ~~maintain an interest coverage ratio (the ratio~~repay funds borrowed under the revolver portion of our ~~consolidated EBITDA~~Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.
We have incurred $2.1 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our consolidated ~~interest expense, in each case as is defined by~~balance sheets. We will amortize these costs over the ~~Credit Agreement) of equal or greater than 2.5 to 1.0 determined as~~term of the ~~last day~~notes.
The notes are senior unsecured obligations, ranking equally in right of ~~each quarter for the four-quarter period ending on the date of determination.~~

~~133~~
payment with our existing unsecured indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking fund payments with respect to these notes. The securities are redeemable at a premium at our option.
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
~~Lehman Brothers is a lender in our Credit Agreement. Lehman Brothers has not funded its portion~~
The future maturities of our borrowing requests since its bankruptcy, and it is uncertain whether it will participate in future borrowing requests. Accordingly, the availability of new borrowings under the Credit Agreement has been reduced by approximately $25.4 million as of December 31, 2008. Our borrowing capacity may be further limited by the Credit Agreement’s financial covenant requirements. Exceptlong-term debt in the ~~case of a default, amounts borrowed under our credit facility will not mature prior to the June 21, 2012 maturity date.~~
year indicated are as follows:
   Debt
Maturities
   (Millions)
2011
   $ —
2012
   398.0
2013
   —
2014
   —
2015
   250.0
Thereafter
   —

Unamortized discount
   (0.2 )

Total
   $ 647.8

~~Bridge Loan~~
In May 2007, we entered into a two-month bridge loan, or the Bridge Loan, which provided for borrowings up to $100.0 million, and had terms and conditions substantially similar to those of our Credit Agreement. In conjunction with our entering into the Bridge Loan, our Credit Agreement was amended to provide for additional unsecured indebtedness, of an amount not to exceed $100.0 million, which was due and payable no later than August 9, 2007.
We used borrowings on the Bridge Loan of $88.0 million to partially fund the Southern Oklahoma acquisition. The remaining $12.0 million available for borrowing on the Bridge Loan was not utilized. We used a portion of the net proceeds of a private placement of limited partner units to extinguish the $88.0 million outstanding on the Bridge Loan in June 2007.
Other Agreements
As of December 31, ~~2008,~~2010, we had ~~an outstanding~~a contingent letter of credit ~~with a counterparty~~for up to ~~our commodity derivative instruments of~~ $10.0 million, on which we pay a fee of 0.50% per annum. This facility reduces the amount of cash we may be required to post as collateral. ~~This letter~~As of December 31, 2010, we have no letters of credit ~~was~~ issued ~~directly by~~on this facility; any letters of credit issued on this facility will incur a ~~financial institution~~fee of 1.75% per annum and ~~does~~will not reduce the available capacity under our credit facility.
12. 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 commodity 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 pricing. 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 at a discount to historical ranges, we experience additional exposure as a result of the relationship. These transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. 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 consolidated statements of operations as a gain or a loss on commodity derivative activity.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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 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 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 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 commodity 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
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 the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations.
At December 31, 2010 we had interest rate swap agreements totaling $450.0 million, of which we have designated $275.0 million as cash flow hedges and account for the remaining $175.0 million under the mark-to-market method of accounting. The entire $450.0 million of these swap agreements mitigate our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014.
We have designated $275.0 million of our interest rate swap agreements 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 consolidated balance sheets and are reclassified into earnings as the hedged transactions impact earnings. The effect that these swaps have on
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
our 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.
As of December 31, 2010, $300.0 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 2.94% 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.
At December 31, 2009 we had interest rate swap agreements totaling $575.0 million, all of which we had designated as cash flow hedges. In conjunction with the issuance of $250.0 million of 3.25% Senior Notes, we paid down our revolving credit facility, discontinued hedge accounting on $225.0 million of our existing swap agreements, terminated certain swap agreements for $1.3 million, and modified certain swap agreements to reduce the total outstanding amount by $125.0 million. Additionally, the term on $150.0 million of the swap agreements was extended through June 2014. This resulted in $450.0 million of these swap agreements mitigating our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014.
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 we or DCP Midstream, LLC were to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties 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 December 31, 2010, we are not a party to any agreements that would be subject to these provisions other than our credit agreement.
Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.
Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2010, we had $64.4 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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 December 31, 2010 if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2010, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $62.6 million.
As of December 31, 2010 our interest rate swaps were in a net liability position of approximately $26.9 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 have the right to request that we net settle the instrument in the form of cash.
Collateral
As of December 31, 2010, we had a contingent letter of credit facility for up to $10.0 million, on which we have no letters of credit issued. DCP Midstream, LLC had issued and outstanding parental guarantees totaling $65.0 million in favor of certain counterparties to our commodity derivative instruments. This contingent letter of credit facility and parental guarantees reduce the amount of cash we may be required to post as collateral. As of December 31, 2010, we had no cash collateral posted with counterparties to our commodity derivative instruments.
Summarized Derivative Information
The following summarizes the balance within AOCI relative to our commodity and interest rate cash flow hedges:
   December 31,
2010 December 31,
2009
   (Millions)
Commodity cash flow hedges:

Net deferred losses in AOCI
   $ (0.3 ) $ (0.8 )
Interest rate cash flow hedges:

Net deferred losses in AOCI
   (27.4 ) (31.1 )

Total AOCI
   $ (27.7 ) $ (31.9 )

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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 consolidated balance sheets, by major category, is summarized as follows:
Balance Sheet Line Item
December 31,
2010 December 31,
2009
Balance Sheet Line Item
December 31,
2010 December 31,
2009
(Millions) (Millions)
Derivative Assets Designated as Hedging Instruments:


Derivative Liabilities Designated as Hedging Instruments:

Interest rate derivatives:

Interest rate derivatives:

Unrealized gains on derivative instruments — current
$ —    $ —
Unrealized losses on derivative instruments — current
$ (12.2 ) $ (20.4 )
Unrealized gains on derivative instruments — long-term
—    —
Unrealized losses on derivative instruments — long-term
(5.4 ) (11.6 )

$ —    $ —    $ (17.6 ) $ (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
$ 1.9    $ 7.3
Unrealized losses on derivative instruments — current
$ (26.0 ) $ (21.1 )
Unrealized gains on derivative instruments —long-term
1.4    2.0
Unrealized losses on derivative instruments — long-term
(40.4 ) (46.4 )

$ 3.3    $ 9.3    $ (66.4 ) $ (67.5 )

Interest rate derivatives:

Interest rate derivatives:

Unrealized gains on derivative instruments — current
$ —    $ —
Unrealized losses on derivative instruments — current
$ (4.8 ) $ —
Unrealized gains on derivative instruments — long-term
—    —
Unrealized losses on derivative instruments — long-term
(4.5 ) —

$ —    $ —    $ (9.3 ) $ —

The following table summarizes the impact on our consolidated balance sheet and consolidated statements of operations of our derivative instruments that are accounted for using the cash flow hedge method of accounting.
Gain (Loss)
Recognized in
AOCI on
Derivatives —
Effective Portion Gain (Loss)
Reclassified From
AOCI to
Earnings —
Effective Portion Gain (Loss)
Recognized in Income
on Derivatives —
Ineffective Portion
and Amount
Excluded From
Effectiveness Testing Deferred
Losses in
AOCI
Expected to be
Reclassified
into Earnings
Over the Next
12 Months

2010 2009 2010    2009 2010 2009
(Millions) (Millions) (Millions) (Millions)
Interest rate derivatives
$ (18.7 ) $ (12.0 ) $ (22.4 )    $ (19.7 ) (a)    $ —    $ — (a)(c) $ (19.1 )
Commodity derivatives
$ —    $ —    $ (0.5 )    $ (0.9 ) (b)    $ —    $ — (b)(c) $ (0.3 )
~~12.~~  (a) Included in interest expense in our consolidated statements of operations.
(b) Included in sales of natural gas, propane, NGLs and condensate in our consolidated statements of operations.
(c) For the year ended December 31, 2010 and 2009, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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 consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:
   Year Ended December 31,
Commodity Derivatives: Statements of Operations Line Item
   2010 2009 2008
   (Millions)
Third party:

Realized
   $ (2.9 ) $ 16.8    $ (25.5 )
Unrealized
   (4.4 ) (79.1 ) 100.9

(Losses) gains from commodity derivative activity, net
   $ (7.3 ) $ (62.3 ) $ 75.4

Affiliates:

Realized
   $ (0.7 ) $ (0.2 ) $ (5.2 )
Unrealized
   (0.5 ) (3.3 ) 1.5

Losses from commodity derivative activity, net — affiliates
   $ (1.2 ) $ (3.5 ) $ (3.7 )

   Year Ended December 31,
Interest Rate Derivatives: Statements of Operations Line Item
   2010 2009    2008
   (Millions)
Third party:

Realized
   $ (1.5 ) $ —       $ —
Unrealized
   3.1    —       —

Interest expense
   $ 1.6    $ —       $ —

We do not have any derivative financial instruments that qualify as a hedge of a net investment.
The following tables represent, 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 tables below.
   December 31, 2010
   Crude Oil Natural Gas Natural Gas
Liquids
Year of Expiration
   Net Long
(Short)
Position
(Bbls) Net Long
(Short)
Position
(MMBtu) Net Long
(Short)
Position
(Bbls)
2011
   (998,554 ) (687,500 ) (73,190 )
2012
   (839,358 ) (366,000 ) —
2013
   (748,250 ) (365,000 ) —
2014
   (547,500 ) (365,000 ) —
2015
   (182,500 ) —    —
   December 31, 2009
   Crude Oil Natural Gas Natural Gas
Liquids
Year of Expiration
   Net Long
(Short)
Position
(Bbls) Net Long
(Short)
position
(MMbtu) Net Long
(Short)
Position
(Bbls)
2010
   (950,225 ) (1,883,500 ) (74,001 )
2011
   (949,000 ) (1,496,500 ) —
2012
   (777,750 ) (1,500,600 ) —
2013
   (748,250 ) (730,000 ) —
2014
   (365,000 ) —    —
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of December 31, 2010 we have swaps with a notional value between $50.0 million and $80.0 million, which, in aggregate, exchange $450.0 million of our floating rate obligation to a fixed rate obligation through June 2012, with $150.0 million extending from June 2012 through June 2014.
13. Partnership Equity and Distributions
General— Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, ~~(defined below)~~as defined below, to unitholders of record on the applicable record date, as determined by our general partner.
In November ~~2007,~~2010, we issued 2,875,000 common limited partner units at $34.96 per unit. We received proceeds of $96.2 million, net of offering costs.
In September 2010, we issued 5,200 common limited partner units, from our Long Term Incentive plan, to non-employee directors as compensation for their service during 2010.
In August 2010, we issued 2,990,000 common limited partner units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs.
On May 26, 2010, we filed a universal shelf registration statement onForm S-3 ~~was declared effective by~~ with the ~~SEC. The universal shelf registration statement has~~SEC with a maximum aggregate offering price of $1.5 billion, ~~which~~to replace an existing shelf registration statement. The universal shelf registration statement will allow us to ~~register~~offer and issue additional partnership units and debt ~~obligations.~~
securities.
In ~~June 2007,~~November 2009, we ~~entered into a private placement agreement with a group of institutional investors for $130.0 million, representing 3,005,780~~issued 2,500,000 common limited partner units at $25.40 per unit, and in December 2009 we issued an additional 375,000 common limited partner units to the underwriters upon exercise of their overallotment option. We received proceeds of $69.5 million, net of offering costs.
In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP Midstream, LLC in consideration for an additional 25.1% interest in East Texas and a fixed price ~~of $43.25~~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.
In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of ~~$128.5~~$132.1 million, net of offering costs.
In July 2007, we issued 620,404 common units to DCP Midstream, LLC as partial consideration for the purchase of Discovery, East Texas and the Swap. In August 2007, we issued 275,735 common units to DCP Midstream, LLC as partial consideration for the purchase of certain subsidiaries of MEG.
In August 2007, we issued 2,380,952 common units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100.0 million in the aggregate.
In January 2008, our registration statement onForm S-3 to register the 3,005,780 common limited partner units represented in the June 2007 private placement agreement and the 2,380,952 common limited partner units represented in the August 2007 private placement agreement was declared effective by the SEC.

~~134~~

~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.1 million, net of offering costs.~~
Definition of Available Cash— Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
less the amount of cash reserves established by the general partner to:
provide for the proper conduct of our business;
• ~~less the amount of cash reserves established by the general partner to:~~
comply with applicable law, any of our debt instruments or other agreements; and
• ~~provide for the proper conduct of our business;~~
• ~~comply with applicable law, any of our debt instruments or other agreements; or~~
• ~~provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;~~
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.~~
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.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
General Partner Interest and Incentive Distribution Rights—~~Prior to June 2007, the~~ The general partner ~~was~~is entitled to 2%a percentage of all quarterly distributions ~~that we make prior~~equal to ~~our liquidation.~~its general partner interest of approximately 1% and limited partner interest of 1% as of December 31, 2010. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. ~~The general partner has not participated in certain issuances of common units. Therefore, the general partner’s 2% interest has been diluted to approximately 1% as of December 31, 2008.~~
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 ~~these private placement agreements,~~our common limited partner unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read theDistributions of ~~Available Cash during the Subordination Periodand~~~~Distributions of~~ Available Cash after the Subordination Periodsections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.
Class CD Units— ~~On July 2, 2007,~~All of the Class CD units were held by DCP Midstream, LLC and converted tointo our common ~~units.~~
units on a one for one basis on August 17, 2009. The holders of the Class D units received the second quarter distribution paid on August 14, 2009.
Subordinated Units —All of ~~the~~our subordinated units ~~are~~were held by DCP Midstream, ~~LLC.~~ LLC and were converted to common limited partner units by February 2009. 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.
Our partnership agreement provides that, during the subordination period, the common units ~~will have~~had the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units ~~will~~were not be entitled to receive any distributions until the common units ~~have~~ received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages ~~will~~could be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The subordination period has an early termination provision that permits 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2008 and the other 50% of the subordinated units to convert to common units on the second business day following the first quarter distribution in 2009, provided the tests for ending the subordination period contained in the partnership agreement are satisfied. In 2008, we determined that the criteria set forth in the partnership agreement for early termination of the subordination period occurred in February 2008 and,

~~135~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
therefore, 50% of the subordinated units, or 3,571,428 units, converted into common units. We determined that the criteria set forth in the partnership agreement for early termination of the subordination period occurred in February 2009 and, therefore, the remaining 3,571,429 units, converted into common units. Our board of directors and the conflicts committee of the board certified that all conditions for early conversion were satisfied. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.
~~Distributions of Available Cash during the Subordination Period~~— Our partnership agreement, after adjustment for the general partner’s relative ownership level, currently approximately 1%, requires that we make distributions of Available Cash for any quarter during the subordination period in the following manner:
• ~~first,~~to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;
• ~~second,~~to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;
• ~~third,~~to the subordinated unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;
• ~~fourth,~~~~to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter (the First Target Distribution);~~
• ~~fifth,~~13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter (the Second Target Distribution);
• ~~sixth,~~23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter (the Third Target Distribution); and
• ~~thereafter,~~~~48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders (the Fourth Target Distribution).~~
Distributions of Available Cash after the Subordination Period— Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period, 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.

~~136~~
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
The following table presents our cash distributions paid in ~~2008, 2007~~2010, 2009 and ~~2006:~~

Per Unit
Total Cash

Payment Date
Distribution Distribution
(Millions)

November 14, 2008 $ 0.600 $ 20.1
August 14, 2008 0.600 20.1
May 15, 2008 0.590 19.6
February 14, 2008 0.570 15.7
November 14, 2007 0.550 14.7
August 14, 2007 0.530 12.4
May 15, 2007 0.465 8.6
February 14, 2007 0.430 7.8
November 14, 2006 0.405 7.4
August 14, 2006 0.380 6.7
May 15, 2006 0.350 6.3
February 13, 2006(a) 0.095 1.7
2008:
Payment Date
   Per Unit
Distribution    Total Cash
Distribution
      (Millions)
November 12, 2010
   $ 0.610       $ 27.4
August 13, 2010
   0.610       25.3
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
November 14, 2008
   0.600       20.1
August 14, 2008
   0.600       20.1
May 15, 2008
   0.590       19.6
February 14, 2008
   0.570       15.7
14.
~~(a)~~ ~~Represents the pro rata portion of our Minimum Quarterly distribution of $0.35 per unit for the period December 7, 2005, the closing of our initial public offering, through December 31, 2005.~~
~~13.~~   ~~Risk Management Activities, Credit Risk and Financial Instruments~~
~~The impact of our derivative activity on our results of operations and financial position is summarized below:~~

Year Ended December 31,
2008 2007 2006
(Millions)

Commodity cash flow hedges:
Losses due to ineffectiveness $ — $ — $ (0.3 )
(Losses) gains reclassified into earnings $ (0.8 ) $ 2.4 $ 2.6
Commodity derivative activity:
Unrealized gains (losses) from derivative activity $ 102.4 $ (81.7 ) $ 0.3
Realized losses from derivative activity $ (30.1 ) $ (5.9 ) $ (0.2 )
Interest rate cash flow hedges:
(Losses) gains reclassified into earnings $ (6.7 ) $ 0.7 $ 0.1

December 31,
2008 2007
(Millions)

Commodity cash flow hedges:
Net deferred losses in AOCI $ (1.8 ) $ (2.6 )
Interest rate cash flow hedges:
Net deferred losses in AOCI $ (38.7 ) $ (12.3 )
For the years ended December 31, 2008, 2007 and 2006, 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.

~~137~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate the effects of the identified risks. In general, we attempt to mitigate risks related to the variability of future cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. We have established a comprehensive risk management policy, or the Risk Management Policy, and a risk management committee, to monitor and manage market risks associated with commodity prices and interest rates. Our Risk Management Policy prohibits the use of derivative instruments for speculative purposes.
As of December 31, 2007, we posted collateral with certain counterparties to our commodity derivative instruments of approximately $18.2 million, which is included in other current assets on the consolidated balance sheet. As of December 31, 2008, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million. This letter of credit reduces the amount of cash we may be required to post as collateral. As of December 31, 2008, we had no cash collateral posted with counterparties to our commodity derivative instruments.
~~Commodity Price Risk~~— Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts to purchase and process natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.
Our wholesale propane logistics business 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 that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. The amount and type of price risk is dependent on the mechanisms and locations for purchases, sales, transportation and storage of propane.
We manage our commodity derivative activities in accordance with our Risk Management Policy, which limits exposure to market risk and requires regular reporting to management of potential financial exposure.
~~Interest Rate Risk~~— Interest rates on credit facility balances 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.
~~Credit Risk~~— In the Natural Gas Services segment, we sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. In the Wholesale Propane Logistics segment, we sell primarily to retail propane distributors. In the NGL Logistics segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Concentration of credit risk may affect our overall credit risk, in that 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,

~~138~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
determined in accordance with DCP Midstream, LLC’s credit policy and guidelines. The 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.
~~Commodity Cash Flow Protection Activities~~— We used NGL, natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. Prior to July 1, 2007, the effective portion of the change in fair value of a derivative designated as a cash flow hedge was accumulated in AOCI. During the period in which the hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were reclassified to the consolidated statements of operations in the same accounts as the item being hedged.
Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. Therefore, we are using the mark-to-market method of accounting for all commodity derivative instruments. As a result, the remaining net loss deferred in AOCI will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings. As of December 31, 2008, deferred net losses of $0.9 million are expected to be reclassified during the next 12 months. Subsequent to July 1, 2007, the changes in fair value of financial derivatives are included in gains and losses from derivative activity in the consolidated statements of operations. The agreements are with major financial institutions, which management expects to fully perform under the terms of the agreements.
As of December 31, 2008, we have mitigated a significant portion of our expected natural gas, NGL and condensate commodity price risk associated with the equity volumes from our gathering and processing operations through 2013 with natural gas, NGLs and crude oil derivatives.
~~Other Asset-Based Activity~~— To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in price variability across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.
Our wholesale propane logistics business 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. 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. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally 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 financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.
~~Commodity Fair Value Hedges~~— Historically, we used fair value hedges to mitigate risk to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) to reduce our cash flow exposure to fixed price risk by swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index-based).
~~Normal Purchases and Normal Sales~~~~— If a contract qualifies and is designated as a normal purchase or normal sale, no recognition of the contract’s fair value in the consolidated financial statements is required until~~

~~139~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
the associated delivery period impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of commodities in future periods as well as select operating expense contracts.
~~Interest Rate Cash Flow Hedges~~— We mitigate a portion of our interest rate risk with interest rate swaps, which reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swap agreements convert the interest rate associated with an aggregate of $575.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the consolidated balance sheets. As of December 31, 2008, $16.0 million of deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. However, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings. $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 LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of the agreements.
~~14.~~   Equity-Based Compensation
Total compensation cost (credit) ~~cost~~ for equity-based arrangements was as follows:

Year Ended December 31,
2008 2007 2006
(Millions)

Performance Units $ (0.7 ) $ 1.1 $ 0.2
Phantom Units (0.4 ) 0.6 0.4
Restricted Phantom Units 0.1 — —

Total compensation (credit) cost $ (1.0 ) $ 1.7 $ 0.6

   Year Ended December 31,
     2010        2009        2008
   (Millions)
Performance Units
   $ 1.2       $ 1.2       $ (0.7 )
Phantom Units
   0.2       0.4       (0.4 )
Restricted Phantom Units
   1.4       0.6       0.1

Total compensation cost (credit)
   $ 2.8       $ 2.2       $ (1.0 )

On November 28, 2005, the board of directors of our General Partner adopted a long-term incentive plan, or LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for ~~us, effective as of December 7, 2005. Under the LTIP, equity-based instruments may be granted to our key employees.~~us. The LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the LTIP. Awards that are canceled or forfeited, or are withheld to satisfy the General Partner’s tax withholding obligations, are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the General Partner’s board of directors. All awards are subject to cliff vesting, with the exception of the Phantom Units issued to directors in conjunction with our initial public offering, which are subject to graded vesting provisions.
~~All~~
Substantially all awards are accounted for as liability awards.
Performance Units— We have awarded phantom LPUs, or Performance Units, pursuant to the LTIP to certain employees. Performance Units generally vest in their entirety at the end of a three year performance period. The number of Performance Units that will ultimately vest range, in value from 0% to 200% of the outstanding Performance Units, depending on the achievement of specified performance targets over three year

~~140~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
performance periods. The final performance payout is determined by the compensation committee of the board of directors of our General Partner. The DERs ~~will be~~are paid in cash at the end of the performance period. Of the remaining Performance Units outstanding at December 31, ~~2008, 21,705 units vested in January 2009, 15,101~~2010, 51,794 units are expected to vest on December 31, ~~2009,~~2011 and ~~8,544~~11,641 units are expected to vest on December 31, ~~2010.~~
2012.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
At December 31, ~~2008,~~2010, there was approximately ~~$0.3~~$1.0 million of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of ~~0.7~~1.2 years. The following table presents information related to the Performance Units:

Grant Date

Weighted-
Measurement

Average Price
Date Price

Units per Unit per Unit

Outstanding at January 1, 2006 — $ —
Granted 40,560 $ 26.96
Forfeited (17,470 ) $ 26.96

Outstanding at December 31, 2006 23,090 $ 26.96
Granted 29,610 $ 37.29
Forfeited (5,740 ) $ 31.39

Outstanding at December 31, 2007 46,960 $ 32.93
Granted 17,085 $ 33.85
Forfeited (12,025 ) $ 32.42

Outstanding at December 31, 2008 52,020 $ 33.35 $ 9.40

Expected to vest(a) 45,350 $ 31.70 $ 9.40
   Units Grant Date
Weighted-
Average Price
per Unit    Measurement
Date Price
per Unit
Outstanding at January 1, 2008
   46,960    $ 34.09
Granted
   17,085    $ 33.85
Forfeited
   (12,025 ) $ 33.14

Outstanding at December 31, 2008
   52,020    $ 34.23
Granted
   52,450    $ 10.05
Vested
   (37,330 ) $ 34.51

Outstanding at December 31, 2009
   67,140    $ 15.18
Granted
   16,630    $ 31.80
Vested(a)
   (14,215 ) $ 33.44
Forfeited
   (2,205 ) $ 15.61

Outstanding at December 31, 2010
   67,350    $ 15.42       $ 37.40

Expected to vest(b)
   63,435    $ 14.04       $ 37.40
(a) The units vested at 0%.
(b) Based on our December 31, ~~2008~~2010 estimated achievement of specified performance targets, the performance ~~target~~estimate for units granted in ~~2008~~2010 is 100%~~, for units granted in 2007 is 102%~~, and for units granted in ~~2006~~2009 is ~~140.4%~~125%. The estimated forfeiture rate for units granted in ~~2008 and 2007~~2010 is ~~50%,~~30% and for units granted in ~~2006~~2009 is 0%21%.
The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.
The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to Performance Units, including the related DERs:
   Units Vested Fair Value of
Units Vested    Unit-Based
Liabilities Paid
   (Millions)
2010
   14,215    $ —       $ 0.8 (a)
2009
   37,330 (a) $ 1.1       $ 0.3
(a) 22,860, or $0.8 million, of the units and the related DERs that vested in 2009 were paid in 2010.
Phantom Units— In conjunction with our initial public offering, in January 2006 our General Partner’s board of directors awarded phantom LPUs, or Phantom Units, to key employees, and to directors who are not officers or employees of affiliates of the General Partner. ~~The remaining Phantom Units outstanding at December 31, 2008 vested on January 3, 2009.~~
In ~~2007,~~2010, we granted ~~4,500~~5,200 Phantom Units, pursuant to the LTIP, to directors who are not officers or employees of affiliates of the General Partner as part of their annual director fees for ~~2007. Of~~2010. All of these units ~~4,000~~vested in 2010 and were settled in units.
In 2009, we granted 16,000 Phantom Units, pursuant to the LTIP, to directors who are not officers or employees of affiliates of the General Partner as part of their annual director fees for 2009. All of these units vested during ~~2007~~2009 and ~~500 units vested~~were settled in ~~February 2008.~~
cash.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
In 2008, we granted 4,000 Phantom Units, pursuant to the LTIP, to directors who are not officers or employees of affiliates of the General Partner as part of their annual director fees for 2008. All of these units vested during ~~2008.~~
2008 and were settled in cash.
The DERs are paid in cash quarterly in arrears.

~~141~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
The following table presents information related to the Phantom Units:

Grant Date

Weighted-
Measurement

Average Price
Date Price

Units per Unit per Unit

Outstanding at January 1, 2006 — $ —
Granted 35,900 $ 24.05
Forfeited (11,200 ) $ 24.05

Outstanding at December 31, 2006 24,700 $ 24.05
Granted 4,500 $ 42.90
Forfeited (2,333 ) $ 24.05
Vested (6,668 ) $ 35.23

Outstanding at December 31, 2007 20,199 $ 24.56
Granted 4,000 $ 35.88
Forfeited (4,000 ) $ 24.05
Vested (6,501 ) $ 32.91

Outstanding at December 31, 2008 13,698 $ 24.05 $ 9.40

Expected to vest 13,698 $ 24.05 $ 9.40
   Units Grant Date
Weighted-
Average Price
per Unit    Measurement
Date Price
per Unit
Outstanding at January 1, 2008
   20,199    $ 24.56
Granted
   4,000    $ 35.88
Forfeited
   (4,000 ) $ 24.05
Vested
   (6,501 ) $ 32.91

Outstanding at December 31, 2008
   13,698    $ 24.05
Granted
   16,000    $ 10.05
Vested
   (29,698 ) $ 16.51

Outstanding at December 31, 2009
   —    $ —
Granted
   5,200    $ 24.05
Vested
   (5,200 ) $ 31.80

Outstanding at December 31, 2010
   —    $ —       $ —

The ~~estimate~~following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to Phantom ~~Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate.~~
Units:
   Units Vested    Fair Value of
Units Vested    Unit-Based
Liabilities Paid
      (Millions)
2010(a)
   5,200       $ 0.2       $ —
2009
   29,698       $ 0.5       $ 0.5
2008
   6,501       $ 0.2       $ 0.2
(a) We issued 5,200 units in September 2010 related to these Phantom Units.
Restricted Phantom Units— Our General Partner’s board of directors awarded restricted phantom LPUs, or RPUs, to key employees under the LTIP. ~~The~~Of the remaining RPUs outstanding at December 31, ~~2008~~2010, 41,436 units are expected to vest on December 31, ~~2011.~~2011 and 11,641 units are expected to vest on December 31, 2012. The DERs are paid in cash quarterly in arrears.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
At December 31, ~~2008,~~2010, there was approximately ~~$0.2~~$0.9 million of unrecognized compensation expense related to the RPUs that is expected to be recognized over a weighted-average period of ~~2.0 years.~~1.0 year. The following table presents information related to the RPUs:

Grant Date

Weighted-
Measurement

Average Price
Date Price

Units per Unit per Unit

Outstanding at January 1, 2008 — $ — $ —
Granted 17,085 $ 33.85
Forfeited (2,395 ) $ 35.88
Vested — $ —

Outstanding at December 31, 2008 14,690 $ 33.52 $ 9.40

Expected to vest 8,544 $ 33.85 $ 9.40
   Units Grant Date
Weighted-
Average Price
per Unit    Measurement
Date Price
per Unit
Outstanding at January 1, 2008
   —    $ —
Granted
   17,085    $ 33.85
Forfeited
   (2,395 ) $ 35.88

Outstanding at December 31, 2008
   14,690    $ 33.52
Granted
   52,450    $ 10.05

Outstanding at December 31, 2009
   67,140    $ 15.18
Granted
   16,630    $ 31.80
Vested
   (14,215 ) $ 33.44
Forfeited
   (2,205 ) $ 15.61

Outstanding at December 31, 2010
   67,350    $ 15.42       $ 37.40

Expected to vest
   66,403    $ 18.64       $ 37.40
The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to Restricted Phantom Units:
   Units Vested    Fair Value of
Units Vested    Unit-Based
Liabilities Paid
      (Millions)
2010(a)
   14,215       $ 0.5       $ —
(a) 14,215 of the units and the related DERs that vested in 2010 were paid in 2011.
The estimate of RPUs that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate, which was estimated at ~~50% as of December 31,~~30% for units granted in 2010, 21% for units granted in 2009 and 22% for units granted in 2008. Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.
We intend to settle certain awards issued under the LTIP in cash upon vesting. Compensation expense on these awards is recognized ratably over each vesting period, and will be ~~remeasured~~re-measured each reporting period for

~~142~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of our common units at each measurement date.
15.
~~15.~~   Income Taxes
We are structured as a master limited partnership, which is a pass-through entity for federal income tax purposes. Accordingly, we had no federal deferred tax balances as of December 31, ~~2008, 2007~~2009 and ~~2006,~~2008, and no federal income tax expense for the years ended December 31, 2010, 2009 and 2008. On December 30, 2010, we acquired all of the interests in Marysville Hydrocarbons Holdings, LLC, an entity that owns a taxable C-Corporation consolidated return group. We have estimated $35.0 million of federal deferred tax liabilities resulting from built-in tax gains recognized in the transaction and have recorded this in our preliminary purchase price allocation as of December 31, 2010.
On January 4, 2011, we merged two wholly-owned subsidiaries of Marysville Hydrocarbons Holding, LLC and converted the combined entity’s organizational structure from a corporation to a limited liability company. This conversion to a limited liability company triggers the deferred tax liabilities resulting from
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 ~~2007 and 2006.~~
— (Continued)
built-in tax gains to become currently payable. Accordingly, the estimated $35.0 million of deferred tax liabilities at December 31, 2010 will be reflected as current income tax payable on financial statements with reporting periods beginning on or after January 1, 2011.
The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned to Texas. ~~Accordingly, we have recorded current tax expense for the Texas margin tax beginning in 2007.~~ During 2008 and 2009 we acquired properties in Michigan. Michigan imposes a business tax of 0.8% on gross receipts, and 4.95% of Michigan taxable income. The sum of the gross receipts and income tax is subject to a tax surcharge of 21.99%. Michigan provides tax credits that may reduce our final tax liability.
Income tax ~~expense for~~benefit (expense) consists of the ~~years ended~~following:
   Year Ended December 31,
   2010 2009 2008
   (millions)
Current:

State
   $ (0.4 ) $ (0.5 ) $ (0.7 )
Deferred:

State
   0.1    (0.1 ) 0.1

Total income tax expense
   $ (0.3 ) $ (0.6 ) $ (0.6 )

We had additional net long-term deferred tax liabilities of $1.6 million and $1.7 million as of December 31, ~~2008~~2010 and ~~2007, consisted of current expense of $0.1 million for both periods,~~2009, respectively, included in other long term liabilities on the consolidated balance sheets. These state deferred tax liabilities relate to our East Texas operations, and are primarily associated with depreciation related ~~primarily~~ to ~~the Texas margin tax. We did not have income tax expense in 2006.~~ property plant and equipment.
Our effective tax rate differs from statutory rates, primarily due to being structured as a limited partnership, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.
16.
~~16.~~   Net Income or Loss per Limited Partner Unit
Our net income or loss is allocated to the general partner and the limited partners, including the holders of the subordinated units, through the date of subordinated conversion, in accordance with their respective ownership percentages, after ~~giving effect to income or loss allocated to predecessor operations and incentive distributions paid to~~allocating Available Cash generated during the ~~general partner.~~
period in accordance with our partnership agreement.
Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds ~~the First Target Distribution Level,~~our Available Cash it will have the impact of reducing net income per LPU. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of Available Cash and not earnings. In periods in which our aggregate net income does not exceed the First Target Distribution Level, there is no impact on our calculation of earnings per LPU. During the year ended December 31, 2008, our aggregate net income per limited partner unit exceeded the Fourth Target Distribution level, and as a result we allocated an additional $24.8 million in additional earnings to the general partner. During the year ended December 31, 2007, no additional earnings were allocated to the general partner. During the year ended December 31, 2006, our aggregate net income per limited partner unit exceeded the Second Target Distribution level, and as a result we allocated $1.3 million in additional earnings to the general partner.
Basic and diluted net income or loss per LPU is calculated by dividing limited partners’ interest in net income or loss, ~~less pro forma general partner incentive distributions as described above,~~ by the weighted-average number of outstanding LPUs during the period.

~~143~~
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
~~The following table illustrates our calculation of net income per LPU:~~

Year Ended December 31,
2008 2007 2006
(Millions)

Net income (loss) $ 125.7 $ (15.8 ) $ 61.9
Less:
Net income attributable to predecessor operations — (3.6 ) (26.6 )

Net income (loss) attributable to the partnership 125.7 (19.4 ) 35.3
Less: General partner interest in net income (11.9 ) (2.2 ) (0.7 )

Limited partners’ interest in net income or net loss 113.8 (21.6 ) 34.6
Less: Additional earnings allocation to general partner (24.8 ) — (1.3 )

Net income (loss) available to limited partners $ 89.0 $ (21.6 ) $ 33.3

Net income (loss) per LPU — basic and diluted $ 3.25 $ (1.05 ) $ 1.90

17.
~~17.~~   Commitments and Contingent Liabilities
Litigation
~~Driver~~Westfield — In ~~August 2007, Driver Pipeline Company, Inc., or Driver, filed~~July 2010 there was an explosion at a ~~lawsuit against DCP Midstream, LP, an affiliate~~condominium complex in Norfolk, Massachusetts in which a worker at the condominium was killed. An investigation of the ~~owner~~accident by the Massachusetts State Fire Marshall has indicated that the propane that exploded may have been unodorized. The investigation further indicated that the propane that exploded may have been supplied by our Westfield propane rail terminal to one of our ~~general partner, in District Court, Jackson County, Texas. The litigation stems from an ongoing commercial dispute involving~~customers who filled the ~~construction~~tank that exploded. We are not responsible for odorization of the propane we supply to our customers out of our ~~Wilbreeze pipeline,~~Westfield terminal. Rather, we receive the propane by rail which ~~was completed in December 2006. Driver was~~has been odorized by our suppliers. An attorney representing the ~~primary contractor for construction~~estate of the ~~pipeline and~~deceased has brought a legal action against our customer who filled the ~~construction process was managed for us by DCP Midstream, LP. Driver claims damages~~tank that exploded; however, we have not been named in ~~the amount of $2.4 million for breach of contract. We believe Driver’s position in this litigation is without merit and we intend to vigorously defend ourselves against this claim.~~that lawsuit. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
El Paso — On February 27, 2009, a jury in the District ~~Count,~~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.~~Midstream, LLC. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August ~~2000, which includes~~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 ~~of time~~ prior to our ownership of ~~this asset. Our responsibility for this judgment will be limited to~~ the ~~time period after~~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 ~~acquired the asset from~~and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso regarding this matter in ~~December 2005. We intend to appeal this decision~~Texas and ~~will continue to defend ourselves vigorously against this claim. Nevertheless, as a result~~Louisiana. Under the terms of the ~~jury verdict~~settlement agreement, we ~~have reserved a contingent liability of $2.5~~paid El Paso approximately $2.2 million for ~~this matter,~~our portion of the settlement, which is ~~included~~within the amount of our previously disclosed contingent liability. The cases have been dismissed in ~~our consolidated financial statements for the year ended December 31, 2008.~~
both Texas and Louisiana.
Other— We are not a party to any other significant legal proceedings, but are a party to various 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 the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flows.
Insurance— We renewed our insurance policies in May, June and July 2010 for the 2010-2011 insurance year. We contract with ~~a third party insurer for our primary general liability insurance covering third party exposures. DCP Midstream, LLC provides our remaining insurance coverage through third party~~third-party and affiliate insurers for: (1) ~~statutory workers’ compensation insurance; (2)~~ automobile liability insurance for all owned,

~~144~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
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 and (5)~~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
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
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.
Environmental— The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Indemnification— DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors. See the “Indemnification” section of Note 5 for additional details.
Other Commitments and Contingencies— We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, totaled ~~$12.9~~$12.8 million, ~~$11.4~~$12.1 million and ~~$11.2~~$12.9 million for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, ~~2008:~~

(Millions)

2009 $ 12.4
2010 9.0
2011 7.9
2012 7.0
2013 5.8
Thereafter 2.6

Total minimum rental payments $ 44.7

2010:
   (Millions)
2011
   $ 15.8
2012
   12.5
2013
   9.6
2014
   4.1
2015
   0.6
Thereafter
   1.2

Total minimum rental payments
   $ 43.8

18.
~~18.~~   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 ~~natural gas gathering, processing and transportation system; (2)~~system, our Southern Oklahoma system, ~~acquired in May 2007; (3) our 25% limited liability company interest in East Texas,~~ our 40% limited liability company interest in Discovery, ~~and the Swap, acquired~~our 75% interest in ~~July 2007; (4)~~ our Colorado ~~and~~system, our Wyoming ~~systems, acquired~~system, our 50.1% interest in ~~August 2007;~~our East Texas system, and ~~(5)~~ our Michigan ~~systems, acquired in October 2008.~~

~~145~~
system.
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Wholesale Propane Logistics— The Wholesale Propane Logistics segment consists of six owned rail terminals, one ~~of which was idled in 2007 to consolidate our operations,~~owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several ~~open access~~open-access pipeline terminals.
NGL Logistics— The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, ~~and a non-operated 45% equity interest in~~the Wattenberg NGL transportation pipeline, the Black Lake interstate NGL ~~pipeline. Prior to~~pipeline and the NGL storage facility in Marysville, Michigan.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December ~~7, 2005, our equity interest was 50%. DCP Midstream, LLC owns a 5% interest in Black Lake, effective with the date of our initial public offering,~~31, 2010, 2009 and ~~an affiliate of BP PLC owns the remaining interest and is the operator of Black Lake. The Wilbreeze transportation pipeline began operations in December 2006.~~
2008 — (Continued)
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:

Year Ended December 31, ~~2008:~~

Wholesale

Natural Gas
Propane
NGL

Services Logistics Logistics Other(c) Total
(Millions)

Total operating revenue $ 791.5 $ 483.0 $ 11.3 $ — $ 1,285.8

Gross margin(a) $ 206.5 $ 11.0 $ 7.1 $ — $ 224.6
Operating and maintenance expense (32.1 ) (9.9 ) (1.0 ) — (43.0 )
Depreciation and amortization expense (33.8 ) (1.3 ) (1.4 ) — (36.5 )
General and administrative expense — — — (24.0 ) (24.0 )
Other — 1.5 — — 1.5
Earnings from equity method investments 33.5 — 0.8 — 34.3
Interest income — — — 5.6 5.6
Interest expense — — — (32.8 ) (32.8 )
Income tax expense(b) — — — (0.1 ) (0.1 )
Non-controlling interest in income (3.9 ) — — — (3.9 )

Net income (loss) $ 170.2 $ 1.3 $ 5.5 $ (51.3 ) $ 125.7

Non-cash derivative mark-to-market(d) $ 99.2 $ 2.4 $ — $ (0.6 ) $ 101.0

Capital expenditures $ 36.6 $ 3.3 $ 0.4 $ 0.7 $ 41.0

~~146~~
2010:
   Natural Gas
Services Wholesale
Propane
Logistics NGL
Logistics Other Total
   (Millions)
Total operating revenue
   $ 778.7    $ 473.2    $ 17.6    $ —    $ 1,269.5

Gross margin(a)
   $ 195.1    $ 28.9    $ 12.9    $ —    $ 236.9
Operating and maintenance expense
   (63.5 ) (12.6 ) (3.7 ) —    (79.8 )
Depreciation and amortization expense
   (69.1 ) (1.9 ) (2.6 ) (0.1 ) (73.7 )
General and administrative expense
   —    —    —    (33.7 ) (33.7 )
Earnings from unconsolidated affiliates
   23.0    —    0.8    —    23.8
Other operating income
   1.0    3.0    —    —    4.0
Step acquisition — equity interest re-measurement gain
   —    —    9.1    —    9.1
Interest expense
   —    —    —    (29.1 ) (29.1 )
Income tax expense(b)
   —    —    —    (0.3 ) (0.3 )

Net income (loss)
   86.5    17.4    16.5    (63.2 ) 57.2
Net income attributable to noncontrolling interests
   (9.2 ) —    —    —    (9.2 )

Net income (loss) attributable to partners
   $ 77.3    $ 17.4    $ 16.5    $ (63.2 ) $ 48.0

Non-cash derivative mark-to-market(c)
   $ (4.4 ) $ (1.0 ) $ —    $ 1.4    $ (4.0 )

Capital expenditures
   $ 38.6    $ 0.6    $ 11.5    $ —    $ 50.7

Acquisitions net of cash acquired
   $ —    $ 67.8    $ 135.5    $ —    $ 203.3

Investments in unconsolidated affiliates
   $ 2.3    $ —    $ —    $ —    $ 2.3

Year Ended December 31, 2009:
   Natural Gas
Services Wholesale
Propane
Logistics NGL
Logistics Other Total
   (Millions)
Total operating revenue
   $ 583.7    $ 348.2    $ 10.5    $ —    $ 942.4

Gross margin(a)
   $ 109.7    $ 48.9    $ 7.6    $ —    $ 166.2
Operating and maintenance expense
   (58.2 ) (10.3 ) (1.2 ) —    (69.7 )
Depreciation and amortization expense
   (61.9 ) (1.4 ) (1.4 ) (0.2 ) (64.9 )
General and administrative expense
   —    —    —    (32.3 ) (32.3 )
Earnings from unconsolidated affiliates
   16.6    —    1.9    —    18.5
Interest income
   —    —    —    0.3    0.3
Interest expense
   —    —    —    (28.3 ) (28.3 )
Income tax expense(b)
   —    —    —    (0.6 ) (0.6 )

Net income (loss)
   6.2    37.2    6.9    (61.1 ) (10.8 )
Net income attributable to noncontrolling interests
   (8.3 ) —    —    —    (8.3 )

Net (loss) income attributable to partners
   $ (2.1 ) $ 37.2    $ 6.9    $ (61.1 ) $ (19.1 )

Non-cash derivative mark-to-market(c)
   $ (84.2 ) $ 0.8    $ —    $ (0.4 ) $ (83.8 )

Capital expenditures
   $ 164.3    $ 0.5    $ —    $ —    $ 164.8

Acquisitions net of cash acquired
   $ 44.5    $ —    $ —    $ —    $ 44.5

Investments in unconsolidated affiliates
   $ 7.0    $ —    $ —    $ —    $ 7.0

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)

Year Ended December 31, ~~2007:~~

Wholesale

Natural Gas
Propane
NGL

Services Logistics Logistics Other(c) Total
(Millions)

Total operating revenue $ 404.1 $ 459.6 $ 9.6 $ — $ 873.3

Gross margin(a) $ 16.2 $ 25.5 $ 4.9 $ — $ 46.6
Operating and maintenance expense (20.9 ) (10.4 ) (0.8 ) — (32.1 )
Depreciation and amortization expense (21.9 ) (1.1 ) (1.4 ) — (24.4 )
General and administrative expense — — — (24.1 ) (24.1 )
Earnings from equity method investments 38.7 — 0.6 — 39.3
Interest income — — — 5.3 5.3
Interest expense — — — (25.8 ) (25.8 )
Income tax expense(b) — — — (0.1 ) (0.1 )
Non-controlling interest in income (0.5 ) — — — (0.5 )

Net income (loss) $ 11.6 $ 14.0 $ 3.3 $ (44.7 ) $ (15.8 )

Non-cash derivative mark-to-market(d) $ (78.3 ) $ (2.8 ) $ — $ — $ (81.1 )

Capital expenditures $ 16.2 $ 3.9 $ 1.2 $ — $ 21.3

~~Year Ended December 31, 2006:~~

Wholesale

Natural Gas
Propane
NGL

Services Logistics Logistics Other(c) Total
(Millions)

Total operating revenue $ 415.3 $ 375.2 $ 5.3 $ — $ 795.8

Gross margin(a) $ 75.3 $ 16.0 $ 4.1 $ — $ 95.4
Operating and maintenance expense (13.5 ) (8.6 ) (1.6 ) — (23.7 )
Depreciation and amortization expense (11.1 ) (0.8 ) (0.9 ) — (12.8 )
General and administrative expense — — — (21.0 ) (21.0 )
Earnings from equity method investments 28.9 — 0.3 — 29.2
Interest income — — — 6.3 6.3
Interest expense — — — (11.5 ) (11.5 )

Net income (loss) $ 79.6 $ 6.6 $ 1.9 $ (26.2 ) $ 61.9

Non-cash derivative mark-to-market(d) $ 0.1 $ — $ — $ — $ 0.1

Capital expenditures $ 6.5 $ 9.4 $ 11.3 $ — $ 27.2

~~147~~
2008:
   Natural Gas
Services Wholesale
Propane
Logistics NGL
Logistics Other Total
   (Millions)
Total operating revenue
   $ 1,336.2    $ 483.0    $ 11.3    $ —    $ 1,830.5

Gross margin(a)
   $ 331.4    $ 11.0    $ 7.1    $ —    $ 349.5
Operating and maintenance expense
   (66.5 ) (9.9 ) (1.0 ) —    (77.4 )
Depreciation and amortization expense
   (50.5 ) (1.3 ) (1.4 ) —    (53.2 )
General and administrative expense
   —    —    —    (33.3 ) (33.3 )
Other
   —    1.5    —    —    1.5
Earnings from unconsolidated affiliates
   17.4    —    0.8    —    18.2
Interest income
   —    —    —    6.1    6.1
Interest expense
   —    —    —    (32.8 ) (32.8 )
Income tax expense(b)
   —    —    —    (0.6 ) (0.6 )

Net income (loss)
   231.8    1.3    5.5    (60.6 ) 178.0
Net income attributable to noncontrolling interests
   (36.1 ) —    —    —    (36.1 )
��
Net income (loss) attributable to partners
   $ 195.7    $ 1.3    $ 5.5    $ (60.6 ) $ 141.9

Non-cash derivative mark-to-market(c)
   $ 99.2    $ 2.4    $ —    $ (0.6 ) $ 101.0

Capital expenditures
   $ 68.3    $ 3.3    $ 0.4    $ 0.7    $ 72.7

Acquisitions net of cash acquired
   $ 157.3    $ —    $ —    $ —    $ 157.3

Investments in unconsolidated affiliates
   $ 7.4    $ —    $ —    $ —    $ 7.4

   December 31,
   2010    2009    2008
   (Millions)
Segment long-term assets:

Natural Gas Services(d)
   $ 1,141.1       $ 1,185.2       $ 1,045.9
Wholesale Propane Logistics(d)
   101.7       53.2       54.3
NGL Logistics(d)
   220.6       32.3       33.8
Other(e)
   4.1       13.1       70.3

Total long-term assets
   1,467.5       1,283.8       1,204.3
Current assets
   233.1       197.7       215.4

Total assets
   $ 1,700.6       $ 1,481.5       $ 1,419.7

~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

December 31,
2008 2007
(Millions)

Segment long-term assets:
Natural Gas Services(e) $ 856.4 $ 710.7
Wholesale Propane Logistics 54.3 52.6
NGL Logistics 33.8 34.8
Other(f) 70.3 104.1

Total long-term assets 1,014.8 902.2
Current assets 165.2 218.5

Total assets $ 1,180.0 $ 1,120.7

(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
(b) Income tax expense ~~in 2008 and 2007~~ relates primarily to the Texas margin tax and the Michigan business tax.
(c) ~~Other consists of general and administrative expense, interest income, interest expense and income tax expense.~~
~~(d)~~ Non-cash derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
~~(e)~~ (d) Long-term assets for our Natural Gas Services segment increased in ~~2008~~2009 as a result of our ~~acquisition of MPP~~expansion projects in ~~October 2008,~~East Texas and ~~in 2007 as a result of our Southern Oklahoma acquisition in May 2007, and our~~the Piceance Basin, the acquisition of certain ~~MEG subsidiaries in August 2007. Long-term~~companies that held natural gas gathering and treating assets for ~~our Natural Gas Services segment include the effects of our 25% equity interest in East Texas, our 40% equity interest in Discovery and the Swap acquired in July 2007, for all periods presented.~~$45.1 million from MichCon Pipeline Company.
Long-term assets for our Wholesale Propane Logistics segment increased in 2010 as a result of our acquisition of Atlantic Energy from a subsidiary of UGI Corporation.
Long-term assets for our NGL Logistics segment increased in 2010 as a result of our acquisitions of the Wattenberg pipeline, Black Lake and Marysville. Our July 30, 2010 acquisition of an additional 50% interest in Black Lake from an affiliate of BP PLC brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
~~(f)~~ (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.
~~148~~
~~DCP MIDSTREAM PARTNERS, LP~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
19.
~~19.~~   Supplemental Cash Flow Information

Year Ended December 31,
2008 2007 2006
(Millions)

Cash paid for interest:
Cash paid for interest, net of amounts capitalized $ 26.3 $ 26.5 $ 11.1
Non-cash investing and financing activities:
Non-cash additions of property, plant and equipment $ 1.5 $ 5.9 $ 1.4
Accounts payable related to acquisitions $ — $ 9.0 $ 9.9
Accrued distributions to DCP Midstream, LLC related to reimbursements $ — $ 0.5 $ —
Accrued contributions from DCP Midstream, LLC related to reimbursements $ — $ 0.3 $ —
Accrued equity-based compensation $ 0.2 $ 0.2 $ —
   Year Ended December 31,
     2010        2009        2008
   (Millions)
Cash paid for interest:

Cash paid for interest, net of amounts capitalized
   $ 7.8       $ 9.0       $ 26.3
Cash paid for income taxes, net of income tax refunds
   $ 0.5       $ 1.5       $ —
Non-cash investing and financing activities:

Property, plant and equipment acquired with accounts payable
   $ 6.3       $ 4.1       $ 17.4
Other non-cash additions of property, plant and equipment
   $ 2.0       $ 1.3       $ 5.5
Accounts payable related to equity issuance costs
   $ 0.2       $ —       $ —
Acquisition related contingent consideration
   $ 1.0       $ —       $ —
Non-cash contribution from noncontrolling interests
   $ 0.5       $ —       $ —
Accrued equity-based compensation
   $ —       $ —       $ 0.2
20.
~~20.~~   Quarterly Financial Data (Unaudited)
Our consolidated results of operations by quarter for the years ended December 31, ~~2008, 2007~~2010 and ~~2006~~2009 were as follows (millions, except per unit amounts):

Year Ended

December 31,
2008
First Second Third Fourth 2008

Total operating revenues $ 337.7 $ 145.9 $ 426.8 $ 375.4 $ 1,285.8
Operating (loss) income $ (16.6 ) $ (165.7 ) $ 152.4 $ 152.5 $ 122.6
Net (loss) income $ (6.5 ) $ (159.3 ) $ 152.7 $ 138.8 $ 125.7
Limited partners’ interest in net (loss) income $ (8.2 ) $ (159.8 ) $ 147.8 $ 134.0 $ 113.8
Basic net (loss) income per limited partner unit $ (0.33 ) $ (5.66 ) $ 2.97 $ 2.72 $ 3.25

Year Ended

December 31,
2007
First Second Third Fourth 2007

Total operating revenues $ 237.2 $ 181.1 $ 188.6 $ 266.4 $ 873.3
Operating income (loss) $ 11.5 $ (1.8 ) $ 3.9 $ (47.6 ) $ (34.0 )
Net income (loss) $ 15.8 $ 0.8 $ 7.5 $ (39.9 ) $ (15.8 )
Limited partners’ interest in net income (loss)(a) $ 12.2 $ 0.2 $ 6.6 $ (40.6 ) $ (21.6 )
Basic net income (loss) per limited partner unit(a) $ 0.58 $ 0.01 $ 0.29 $ (1.69 ) $ (1.05 )

Year Ended

December 31,
2006
First Second Third Fourth 2006

Total operating revenues $ 265.4 $ 160.1 $ 162.8 $ 207.5 $ 795.8
Operating income $ 9.1 $ 9.3 $ 7.3 $ 12.2 $ 37.9
Net income $ 16.3 $ 15.7 $ 14.3 $ 15.6 $ 61.9
Limited partners’ interest in net income(a)(b) $ 5.3 $ 8.6 $ 9.5 $ 11.1 $ 34.6
Basic net income per limited partner unit(a)(b) $ 0.30 $ 0.47 $ 0.51 $ 0.55 $ 1.90

~~149~~
2010
   First Second Third Fourth Year Ended
December 31,
2010
Total operating revenues
   $ 403.7    $ 277.5    $ 239.9    $ 348.4    $ 1,269.5
Operating income
   $ 25.5    $ 27.8    $ 2.7    $ 6.8    $ 62.8
Net income (loss)
   $ 25.9    $ 27.0    $ (0.8 ) $ 5.1    $ 57.2
Net (income) loss attributable to noncontrolling interests
   $ (0.1 ) $ (1.0 ) $ (3.3 ) $ (4.8 ) $ (9.2 )
Net income (loss) attributable to partners
   $ 25.8    $ 26.0    $ (4.1 ) $ 0.3    $ 48.0
Limited partners’ interest in net income (loss)
   $ 22.0    $ 21.8    $ (8.2 ) $ (4.5 ) $ 31.1
Basic net income (loss) per limited partner unit
   $ 0.64    $ 0.63    $ (0.23 ) $ (0.12 ) $ 0.86
DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
2009
   First    Second Third Fourth Year Ended
December 31,
2009
Total operating revenues
   $ 284.4       $ 152.0    $ 205.7    $ 300.3    $ 942.4
Operating income (loss)
   $ 28.1       $ (36.8 ) $ 11.1    $ (3.1 ) $ (0.7 )
Net income (loss)
   $ 19.8       $ (40.0 ) $ 12.4    $ (3.0 ) $ (10.8 )
Net loss (income) attributable to noncontrolling interests
   $ 1.3       $ (2.1 ) $ (2.5 ) $ (5.0 ) $ (8.3 )
Net income (loss) attributable to partners
   $ 21.1       $ (42.1 ) $ 9.9    $ (8.0 ) $ (19.1 )
Limited partners’ interest in net income (loss)(a)
   $ 18.9       $ (44.8 ) $ 6.5    $ (11.4 ) $ (30.8 )
Basic net income (loss) per limited partner unit(a)
   $ 0.67       $ (1.41 ) $ 0.21    $ (0.35 ) $ (0.99 )
(a) Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our additional 25.1% interest in East Texas ~~Discovery and the Swap~~ for the period January 1, ~~2006~~2009 through ~~June 30, 2007.~~
~~(b)~~ Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our wholesale propane logistics business for the period January 1, 2006 through OctoberMarch 31, ~~2006.~~2009.
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
21.
~~21.~~  Supplementary Information — Condensed Consolidating Financial Information ~~Subsequent Events~~
~~On February 27, 2009, a jury in~~
The following condensed consolidating financial information presents the ~~District Count, Harris County, Texas rendered a verdict in favor~~results of ~~El Paso E&P Company, L.P.~~operations, financial position and ~~against one~~cash flows of our subsidiaries and DCP Midstream. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which includes periods of time prior to our ownership of this asset. Our responsibility for this judgment will be limited to the time period after we acquired the asset from DCP Midstream ~~in December 2005. We intend~~Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to ~~appeal this decision~~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 ~~will continue to defend ourselves vigorously against this claim. Nevertheless, as a result~~unconditionally guarantee securities of the ~~jury verdict we have reserved a contingent liability~~subsidiary issuer. For the purpose of ~~$2.5 million for this matter, which is included~~the following financial information, investments in ~~our consolidated~~subsidiaries are reflected in accordance with the equity method of accounting. The financial ~~statements~~information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.
   Condensed Consolidating Balance Sheets
December 31, 2010
   Parent
Guarantor    Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
ASSETS
Current assets:

Cash and cash equivalents
   $       $ 1.5    $ 6.7    $ (1.5 ) $ 6.7
Accounts receivable
   —       —    151.0    —    151.0
Inventories
   —       —    65.2    —    65.2
Other
   —       —    10.2    —    10.2

Total current assets
      1.5    233.1    (1.5 ) 233.1
Property, plant and equipment, net
   —       —    1,169.1    —    1,169.1
Goodwill and intangible assets, net
   —       —    186.7    —    186.7
Advances receivable — consolidated subsidiaries
   333.4       534.7    —    (868.1 ) —
Investments in consolidated subsidiaries
   184.9       323.6    —    (508.5 ) —
Investments in unconsolidated affiliates
   —       —    104.3    —    104.3
Other long-term assets
   —       2.3    5.1    —    7.4

Total assets
   $ 518.3       $ 862.1    $ 1,698.3    $ (1,378.1 ) $ 1,700.6

LIABILITIES AND EQUITY
Accounts payable and other current liabilities
   $ 0.2       $ 19.5    $ 193.0    $ (1.5 ) $ 211.2
Advances payable — consolidated subsidiaries
   —       —    868.1    (868.1 )
Long-term debt
   —       647.8    —    —    647.8
Other long-term liabilities
   —       9.9    93.5    —    103.4

Total liabilities
   0.2       677.2    1,154.6    (869.6 ) 962.4

Commitments and contingent liabilities

Equity:

Partners’ equity

Net equity
   518.1       212.3    323.9    (508.5 ) 545.8
Accumulated other comprehensive loss
   —       (27.4 ) (0.3 ) —    (27.7 )

Total partners’ equity
   518.1       184.9    323.6    (508.5 ) 518.1
Noncontrolling interests
   —       —    220.1    —    220.1

Total equity
   518.1       184.9    543.7    (508.5 ) 738.2

Total liabilities and equity
   $ 518.3       $ 862.1    $ 1,698.3    $ (1,378.1 ) $ 1,700.6

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   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 CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Operations
Year Ended December 31, 2010
   Parent
Guarantor    Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
Operating revenues:

Sales of natural gas, propane, NGLs and condensate
   $ —       $ —    $ 1,162.7    $ —    $ 1,162.7
Transportation, processing and other
   —       —    115.3    —    115.3
Losses from commodity derivative activity, net
   —       —    (8.5 ) —    (8.5 )

Total operating revenues
   —       —    1,269.5    —    1,269.5

Operating costs and expenses:

Purchases of natural gas, propane and NGLs
   —       —    1,032.6    —    1,032.6
Operating and maintenance expense
   —       —    79.8    —    79.8
Depreciation and amortization expense
   —       —    73.7    —    73.7
General and administrative expense
   —       0.2    33.5    —    33.7
Step acquisition — equity interest re-measurement gain
   —       —    (9.1 ) —    (9.1 )
Other, net
   —       —    (4.0 ) —    (4.0 )

Total operating costs and expenses
   —       0.2    1,206.5    —    1,206.7

Operating (loss) income
   —       (0.2 ) 63.0    —    62.8
Interest expense, net
   —       (28.8 ) (0.3 ) —    (29.1 )
Earnings from unconsolidated affiliates
   —       23.8    —    23.8
Earnings (losses) from consolidated subsidiaries
   48.0       77.0    —    (125.0 ) —

Income (loss) before income taxes
   48.0       48.0    86.5    (125.0 ) 57.5
Income tax expense
   —       —    (0.3 ) —    (0.3 )

Net income (loss)
   48.0       48.0    86.2    (125.0 ) 57.2
Net income attributable to noncontrolling interests
   —       —    (9.2 ) —    (9.2 )

Net income (loss) attributable to partners
   $ 48.0       $ 48.0    $ 77.0    $ (125.0 ) $ 48.0

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Operations
Year Ended December 31, 2009
   Parent
Guarantor Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments    Consolidated
   (Millions)
Operating revenues:

Sales of natural gas, propane, NGLs and condensate
   $ —    $ —    $ 913.0    $ —       $ 913.0
Transportation, processing and other
   —    —    95.2    —       95.2
Losses from commodity derivative activity, net
   —    —    (65.8 ) —       (65.8 )

Total operating revenues
   —    —    942.4    —       942.4

Operating costs and expenses:

Purchases of natural gas, propane and NGLs
   —    —    (776.2 ) —       (776.2 )
Operating and maintenance expense
   —    —    (69.7 ) —       (69.7 )
Depreciation and amortization expense
   —    —    (64.9 ) —       (64.9 )
General and administrative expense
   —    (0.1 ) (32.2 ) —       (32.3 )

Total operating costs and expenses
   —    (0.1 ) (943.0 ) —       (943.1 )

Operating loss
   —    (0.1 ) (0.6 ) —       (0.7 )
Interest expense, net
   —    (27.8 ) (0.2 ) —       (28.0 )
Earnings from unconsolidated affiliates
   —    —    18.5    —       18.5
(Losses) Earnings from consolidated subsidiaries
   (19.1 ) 8.8    —    10.3       —

(Loss) income before income taxes
   (19.1 ) (19.1 ) 17.7    10.3       (10.2 )
Income tax expense
   —    —    (0.6 ) —       (0.6 )

Net (loss) income
   (19.1 ) (19.1 ) 17.1    10.3       (10.8 )
Net income attributable to noncontrolling interests
   —    —    (8.3 ) —       (8.3 )

Net (loss) income attributable to partners
   $ (19.1 ) $ (19.1 ) $ 8.8    $ 10.3       $ (19.1 )

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Operations
Year Ended December 31, 2008
   Parent
Guarantor    Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
Operating revenues:

Sales of natural gas, propane, NGLs and condensate
   $ —       $ —    $ 1,672.7    $ —    $ 1,672.7
Transportation, processing and other
   —       —    86.1    —    86.1
Gains from commodity derivative activity, net
   —       —    71.7    —    71.7

Total operating revenues
   —       —    1,830.5    —    1,830.5

Operating costs and expenses:

Purchases of natural gas, propane and NGLs
   —       —    (1,481.0 ) —    (1,481.0 )
Operating and maintenance expense
   —       —    (77.4 ) —    (77.4 )
Depreciation and amortization expense
   —       —    (53.2 ) —    (53.2 )
General and administrative expense
   —       (0.1 ) (33.2 ) —    (33.3 )
Other, net
   —       —    1.5    —    1.5

Total operating costs and expenses
   —       (0.1 ) (1,643.3 ) —    (1,643.4 )

Operating (loss) income
   —       (0.1 ) 187.2    —    187.1
Interest (expense) income, net
   —       (27.1 ) 0.4    —    (26.7 )
Earnings from unconsolidated affiliates
   —       —    18.2    —    18.2
Earnings from consolidated subsidiaries
   141.9       169.1    —    (311.0 ) —

Income before income taxes
   141.9       141.9    205.8    (311.0 ) 178.6
Income tax expense
   —       —    (0.6 ) —    (0.6 )

Net income
   141.9       141.9    205.2    (311.0 ) 178.0
Net income attributable to noncontrolling interests
   —       —    (36.1 ) —    (36.1 )

Net income attributable to partners
   $ 141.9       $ 141.9    $ 169.1    $ (311.0 ) $ 141.9

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2010
   Parent
Guarantor Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
OPERATING ACTIVITIES

Net cash (used in) provided by operating activities
   $ (87.4 ) $ (42.9 ) $ 271.8    $ (0.7 ) $ 140.8

INVESTING ACTIVITIES:

Capital expenditures
   —    —    (50.7 ) —    (50.7 )
Acquisitions, net of cash acquired
   —    —    (203.3 ) —    (203.3 )
Investments in unconsolidated affiliates
   —    —    (2.3 ) —    (2.3 )
Return of investment from unconsolidated affiliate
   —    —    1.2    —    1.2
Proceeds from sale of assets
   —    —    3.4    —    3.4
Purchase of available-for-sale securities
   —    —    —    —    —
Proceeds from sales of available-for-sale securities
   —    10.1    —    —    10.1

Net cash provided by (used in) investing activities
   —    10.1    (251.7 ) —    (241.6 )

FINANCING ACTIVITIES:

Proceeds from debt
   —    868.2    —    —    868.2
Payments of debt
   —    (833.4 ) —    —    (833.4 )
Payment of deferred financing costs
   —    (2.1 ) —    —    (2.1 )
Proceeds from issuance of common units, net of offering costs
   189.3    —    —    —    189.3
Purchase of additional interest in a subsidiary
   —    —    (3.5 ) —    (3.5 )
Distributions to unitholders and general partner
   (101.9 ) —    —    —    (101.9 )
Distributions to noncontrolling interests
   —    —    (25.6 ) —    (25.6 )
Contributions from noncontrolling interests
   —    —    13.8    —    13.8
Contributions from DCP Midstream, LLC
   —    —    0.6    —    0.6

Net cash provided by (used in) financing activities
   87.4    32.7    (14.7 ) —    (105.4 )

Net change in cash and cash equivalents
   —    (0.1 ) 5.4    (0.7 ) 4.6
Cash and cash equivalents, beginning of period
   —    1.6    1.3    (0.8 ) 2.1

Cash and cash equivalents, end of period
   $ —    $ 1.5    $ 6.7    $ (1.5 ) $ 6.7

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2009
   Parent
Guarantor Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
OPERATING ACTIVITIES

Net cash provided by (used in) operating activities
   $ 15.8    $ (31.5 ) $ 124.1    $ (0.5 ) $ 107.9

INVESTING ACTIVITIES:

Capital expenditures
   —    —    (164.8 ) —    (164.8 )
Acquisitions, net of cash acquired
   —    —    (44.5 ) —    (44.5 )
Investments in unconsolidated affiliates
   —    —    (7.0 ) —    (7.0 )
Return of investment from unconsolidated affiliate
   2.2    —    2.2
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
   —    51.1    —    —    51.1

Net cash provided by (used in) investing activities
   —    50.0    (213.8 ) —    (163.8 )

FINANCING ACTIVITIES:

Proceeds from debt
   —    237.0    —    —    237.0
Payments of debt
   —    (280.5 ) —    —    (280.5 )
Proceeds from issuance of common units, net of offering costs
   69.5    —    —    —    69.5
Net change in advances to predecessor from DCP Midstream, LLC
   —    —    3.0    —    3.0
Distributions to unitholders and general partner
   (85.3 ) —    —    —    (85.3 )
Distributions to noncontrolling interests
   —    —    (27.0 ) —    (27.0 )
Contributions from noncontrolling interests
   —    —    78.7    —    78.7
Contributions from DCP Midstream, LLC
   —    —    0.7    —    0.7

Net cash (used in) provided by financing activities
   (15.8 ) (43.5 ) 55.4    —    (3.9 )

Net change in cash and cash equivalents
   —    (25.0 ) (34.3 ) (0.5 ) (59.8 )
Cash and cash equivalents, beginning of period
   —    26.6    35.6    (0.3 ) 61.9

Cash and cash equivalents, end of period
   $ —    $ 1.6    $ 1.3    $ (0.8 ) $ 2.1

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
   Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2008
   Parent
Guarantor Subsidiary
Issuer Non-
Guarantor
Subsidiaries Consolidating
Adjustments Consolidated
   (Millions)
OPERATING ACTIVITIES

Net cash (used in) provided by operating activities
   $ (56.4 ) $ (52.8 ) $ 285.5    $ 1.3    $ 177.6

INVESTING ACTIVITIES:

Capital expenditures
   —    —    (72.7 ) —    (72.7 )
Acquisitions, net of cash acquired
   —    —    (157.3 ) —    (157.3 )
Investments in unconsolidated affiliates
   —    —    (7.4 ) —    (7.4 )
Proceeds from sale of assets
   —    —    2.9    —    2.9
Purchase of available-for-sale securities
   —    (608.2 ) —    —    (608.2 )
Proceeds from sales of available-for-sale securities
   —    650.5    —    —    650.5

Net cash provided by (used in) investing activities
   —    42.3    (234.5 ) —    (192.2 )

FINANCING ACTIVITIES:

Proceeds from debt
   —    660.4    —    —    660.4
Payments of debt
   —    (633.9 ) —    —    (633.9 )
Proceeds from issuance of common units, net of offering costs
   132.1    —    —    —    132.1
Net change in advances to predecessor from DCP Midstream, LLC
   —    —    (14.2 ) —    (14.2 )
Distributions to unitholders and general partner
   (75.7 ) —    (0.5 ) —    (76.2 )
Distributions to noncontrolling interests
   —    —    (46.4 ) —    (46.4 )
Contributions from noncontrolling interests
   —    —    21.3    —    21.3
Contributions from DCP Midstream, LLC
   —    —    4.1    —    4.1

Net cash provided by (used in) financing activities
   56.4    26.5    (35.7 ) —    47.2

Net change in cash and cash equivalents
   —    16.0    15.3    1.3    32.6
Cash and cash equivalents, beginning of period
   —    10.6    20.3    (1.6 ) 29.3

Cash and cash equivalents, end of period
   $ —    $ 26.6    $ 35.6    $ (0.3 ) $ 61.9

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
22. Valuation and Qualifying Accounts and Reserves
Our valuation and qualifying accounts and reserves for the ~~year~~years ended December 31, ~~2008.~~
On February 25, 2009, we entered into a Contribution Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC will contribute an additional 25.1% interest in East Texas to us in exchange for 3.5 million Class D units, providing us with a 50.1% interest in East Texas following the expected closing of the transaction in April 2009. This closing date is subject to extension for up to 45 days to allow for repairs or replacement to our reasonable satisfaction any assets destroyed or damaged by certain casualty losses and time to enable the plant to process all available inlet volumes as defined in the Contribution Agreement. The Class D units will automatically convert into common units in August2010, 2009 and will not be eligible to receive a distribution until the second quarter distribution payable in August 2009. DCP Midstream, LLC has agreed to provide a fixed-price NGL derivative by NGL component for the period of April 2009 to March 2010 for the acquired interest. Subsequent to this transaction, we will consolidate East Texas in our consolidated financial statements.
~~On February 11, 2009, we announced, along with DCP Midstream, LLC, that our East Texas natural gas processing complex and residue natural gas delivery system known~~2008 are as the Carthage Hub, have been temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. No employees or contractors were injured in the incident. There was no significant damage to the natural gas processing complex. As of February 25, 2009, the complex began processing through one of the five plants, and it is expected that full processing capacities will be restored for the entire complex over the next 30 days. Residue gas will be redelivered into limited available pipeline interconnects while the Carthage Hub undergoes inspection and repairs.
On February 17, 2009, the remaining 3,571,429 DCP Partners subordinated units were converted to common units following the completion of the subordination period and satisfactory completion of all subordination period tests contained in the DCP Partners’ partnership agreement.
In February 2009, we entered into interest rate swap agreements to convert $275.0 million of the indebtedness on our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to interest rate fluctuations. These interest rate swaps commence in December 2010 and expire in June 2012
follows:
   Balance at
Beginning
of Period    Charged to
Consolidated
Statements of
Operations    Charged
to Other
Accounts    Deductions/
Other Balance at
End of
Period
   (Millions)
December 31, 2010

Allowance for doubtful accounts
   $ 0.5       $ —       $ —       $ —    $ 0.5
Environmental
   1.1       1.0       —       (0.2 ) 1.9
Litigation
   2.4       0.3       —       (2.5 ) 0.2
Other (a)
   0.1       —       1.0       (1.1 ) —

   $ 4.1       $ 1.3       $ 1.0       $ (3.8 ) $ 2.6

December 31, 2009

Allowance for doubtful accounts
   $ 1.0       $ —       $ —       $ (0.5 ) $ 0.5
Environmental
   1.9       —       —       (0.8 ) 1.1
Litigation
   2.5       —       —       (0.1 ) 2.4
Other (a)
   0.1       —       —       —    0.1

   $ 5.5       $ —       $ —       $ (1.4 ) $ 4.1

December 31, 2008

Allowance for doubtful accounts
   $ 1.7       $ —       $ —       $ (0.7 ) $ 1.0
Environmental
   1.8       0.5       —       (0.4 ) 1.9
Litigation
   —       2.5       —       —    2.5
Other (a)
   —       —       —       0.1    0.1

   $ 3.5       $ 3.0       $ —       $ (1.0 ) $ 5.5

(a) Principally consists of other contingency liabilities, which are included in other current liabilities, and the recognition and re-measurement of the fair value of contingent consideration.
23. Subsequent Events
On January 27, ~~2009,~~2011, the board of directors of the ~~General Partner~~general partner declared a quarterly distribution of ~~$0.60~~$0.6175 per unit, payable on February ~~13, 2009~~14, 2011 to unitholders of record on February ~~6, 2009.~~

~~150~~
7, 2011.
On January 13, 2011, we paid $7.5 million to the sellers of Michigan Pipeline & Processing, LLC, or MPP, which we purchased in October 2008, under our contingent payment agreement whereby we would pay up to an additional $15.0 million to the sellers depending on the earnings of MPP after a three-year period.
On January 1, 2011, we acquired a 33.33% interest in Southeast Texas for $150.0 million, in a transaction among entities under common control. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines; three natural gas processing plants with recently increased processing capacity totaling 380 MMcf/d; and natural gas storage assets with 9 Bcf of existing storage capacity. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2010, 2009 and 2008 — (Continued)
Southeast Texas. The results of the Southeast Texas system will be included in our Natural Gas Services segment. 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 consolidated financial statements will be adjusted to include the historical results of Southeast Texas in subsequent filings, however, the accounting for our acquisition of the interest in Southeast Texas was incomplete at the time we issued our consolidated financial statements. Given the recent timing of the acquisition, we were unable to calculate supplemental pro-forma combined information. The required disclosures will be made in a subsequent filing.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There were no changes in or disagreements with accountants on accounting and financial disclosures during the year ended December 31, ~~2008.~~
2010.
Item 9A. Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, ~~2008,~~2010, pursuant toRule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of December 31, ~~2008,~~2010, our disclosure controls and procedures were effective. There were no changes in internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of ~~2008~~2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report On Internal Control Over Financial Reporting
Our general partner is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange ActRules 13a-15(f) and15d-15(f). Our internal control system was designed to provide reasonable assurance to our management and board of directors of our general partner regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, ~~2008~~2010 based on the framework in “Internal ~~Control —~~ Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.” Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, ~~2008.~~
2010.
Deloitte & Touche, LLP, an independent registered public accounting firm, has issued their report, included immediately following, regarding our internal control over financial reporting.
March ~~4, 2009~~

~~151~~1, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream ~~Partners~~ GP, LLC
Denver, Colorado
We have audited the internal control over financial reporting of DCP Midstream Partners, LP and subsidiaries (the “Company”) as of December 31, ~~2008,~~2010, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report Onon Internal Control ~~Over~~over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

~~152~~
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2008,~~2010, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements ~~and financial statement schedule~~ as of and for the year ended December 31, ~~2008~~2010 of the Company and our report dated March ~~4, 2009~~1, 2011 expressed an unqualified opinion ~~(including explanatory paragraphs referring to (1) the preparation of the portion of the DCP Midstream Partners, LP~~on those consolidated financial statements ~~attributable~~and included an explanatory paragraph referring to the ~~wholesale propane logistics business from the separate records maintained by DCP Midstream, LLC and (2) the preparation~~retroactive effect of the ~~portion~~April 1, 2009 acquisition of ~~the DCP Midstream Partners, LP consolidated financial statements attributable to the~~an additional 25.1% of DCP East Texas Holdings, LLC, ~~Discovery Producer Services, LLC, and~~which was accounted for in a ~~nontrading derivative instrument from the separate records maintained by DCP Midstream, LLC) on those financial statements and financial statement schedule.~~
manner similar to a pooling of interests.
/s/ Deloitte & Touche LLP
Denver, Colorado
March ~~4, 2009~~

~~153~~1, 2011
Item 9B. ~~Item 9B.~~  Other Information
No information was required to be disclosed in a report on Form 8-K, but not so reported, for the quarter ended December 31, 2010.
PART III
~~Form 8-K,~~ ~~but not so reported, for the quarter ended December 31, 2008.~~
~~PART III~~Item 10.
Directors, Executive Officers and Corporate Governance
~~Item 10.~~ ~~Directors, Executive Officers and Corporate Governance~~
~~Management of DCP Midstream Partners, LP~~
Management of DCP Midstream Partners, LP
We do not have directors or officers, which is commonly the case with publicly traded partnerships. 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 our General Partner. Our General Partner is wholly-owned by DCP Midstream, LLC. The officers and directors of our General Partner are responsible for managing us. All of the directors of our General Partner are elected annually by DCP Midstream, LLC and all of the officers of our General Partner serve at the discretion of the directors. Unitholders are not entitled to participate, directly or indirectly, in our management or operations.
Board of Directors and Officers
The board of directors of our General Partner that oversees our operations currently has nine members, four of whom are independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on its general partner’s board of directors or to establish a compensation committee or a nominating committee. However, the board of directors of our General Partner has established an audit committee consisting of four independent members of the board, a compensation committee and a special committee to address conflict situations.
Our General Partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with our General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with our General Partner.
The executive officers of our General Partner manage the day-to-day affairs of our business and devote all of their time to our business and affairs, except Mark A. Borer, our CEO and President, who devotes more than 90% of his time to our business and affairs. We also utilize employees of DCP Midstream, LLC to operate our business and provide us with general and administrative services.
Meeting Attendance and Preparation
The board of directors met 13 times in 2010 and members of our current board of directors attended at least 75% of regular and special meetings and meetings of the committees on which they serve, either in person or telephonically, during 2010. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
Directors and Executive Officers
The following table shows information regarding the current directors and the executive officers of DCP Midstream GP, LLC. Directors are elected for one-year terms.
Name
Age
Position with DCP Midstream GP, ~~LP, which in turn is managed by its general partner, DCP Midstream GP,~~ LLC ~~which we refer to as our General Partner. Our General Partner is wholly-owned by DCP Midstream, LLC. The officers and directors of our General Partner are responsible for managing us. All~~
Thomas C. O’Connor
55 Chairman of the ~~directors of our General Partner are elected annually by DCP Midstream, LLC~~Board and ~~all of the officers of our General Partner serve at the discretion of the directors. Unitholders are not entitled to participate, directly or indirectly, in our management or operations.~~
~~Board of Directors and Officers~~
The board of directors of our General Partner that oversees our operations currently has nine members, four of whom are independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on its general partner’s board of directors or to establish a compensation committee or a nominating committee. However, the board of directors of our General Partner has established an audit committee consisting of four independent members of the board, a compensation committee and a special committee to address conflict situations.
Our General Partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with our General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with our General Partner.
~~The executive officers of our General Partner manage the day-to-day affairs of our business and devote all of their time to our business and affairs, except~~ Director
Mark A. Borer ~~our CEO~~
56 President, Chief Executive Officer and Director
Angela A. Minas
46 Vice President ~~who devotes more than 90% of his time to our business~~ and ~~affairs. We also utilize employees of DCP Midstream, LLC to operate our business~~Chief Financial Officer
Michael S. Richards
51 Vice President, General Counsel and ~~provide us with general and administrative services.~~
~~Meeting Attendance and Preparation~~
Members of our board of directors attended at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically, during 2008. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
Secretary

~~154~~Don Baldridge
41 Vice President, Business Development
Paul F. Ferguson, Jr.
61 Director
Alan N. Harris
57 Director
Donald G. Hrap
52 Director
~~Directors and Executive Officers~~
~~The following table shows information regarding the current directors and the executive officers of DCP Midstream GP, LLC. Directors are elected for one-year terms.~~
~~Name~~
~~Age~~
~~Position with DCP Midstream GP, LLC~~
~~Thomas C. O’Connor~~ 53 ~~Chairman of the Board and Director~~
~~Mark A. Borer~~ 54 ~~President, Chief Executive Officer and Director~~
~~Angela A. Minas~~ 44 ~~Vice President and Chief Financial Officer~~
~~Michael S. Richards~~ 49 ~~Vice President, General Counsel and Secretary~~
~~Don Baldridge~~ 39 ~~Vice President, Business Development~~
~~Paul F. Ferguson, Jr.~~ 59John E. Lowe
52 Director
Frank A. McPherson
77 Director
Thomas C. Morris
70 Director
Stephen R. Springer
64       Director
~~Gregory J. Goff~~ 52 ~~Director~~
~~Alan N. Harris~~ 55 ~~Director~~
~~John E. Lowe~~ 50 ~~Director~~
~~Frank A. McPherson~~ 75 ~~Director~~
~~Thomas C. Morris~~ 68 ~~Director~~
~~Stephen R. Springer~~ 62 ~~Director~~
Our directors hold office for one year or until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
~~Thomas C. O’Connor~~was elected Chairman of the Board of DCP Midstream GP, LLC in September 2008, and has been a director of DCP Midstream GP, LLC since December 2007. Mr. O’Connor has over 20 years experience in the natural gas industry with Duke Energy prior to joining DCP Midstream, LLC in November 2007 as Chairman of the board, President and CEO. Mr. O’Connor joined Duke Energy in 1987 where he served in a variety of positions in the company’s natural gas and pipeline operations units. After serving in a number of leadership positions with Duke Energy, he was named President and Chief Executive Officer of Duke Energy Gas Transmission in 2002 and he was named Group Vice President of corporate strategy at Duke Energy in 2005. In 2006 he became Group Executive and Chief Operating Officer of U.S. Franchised Electric and Gas and later in 2006 was named Group Executive and President of Commercial Businesses at Duke Energy.
~~Mark A. Borer~~was elected President and Chief Executive Officer, and director of DCP Midstream GP, LLC in November 2006. Mr. Borer was previously Group Vice President, Marketing and Corporate Development of DCP Midstream, LLC since July 2004. He previously served as Executive Vice President of Marketing and Corporate Development of DCP Midstream, LLC from May 2002 through July 2004. Mr. Borer served as Senior Vice President, Southern Division of DCP Midstream, LLC from April 1999 through May 2002. Prior to that time, Mr. Borer was Vice President of Natural Gas Marketing for Union Pacific Fuels, Inc.
~~Angela A. Minas~~was elected Vice President and Chief Financial Officer of DCP Midstream GP, LLC in September 2008. Ms. Minas was previously Chief Financial Officer, Chief Accounting Officer and Treasurer for Constellation Energy Partners from September 2006 through March 2008. She also served as Managing Director of the Commodities Group at Constellation Energy Group, Inc. from September 2006 through March 2008. Prior to that, Ms. Minas was Senior Vice President, Global Consulting from 2004 to 2006 for SAIC and Vice President, US Consulting from 2002 to 2003 for SAIC. Prior to that, Ms. Minas was a partner with Arthur Andersen LLP from 1997 through 2002.
~~Michael S. Richards~~was elected Vice President, General Counsel and Secretary of DCP Midstream GP, LLC in September 2005. Mr. Richards was previously Assistant General Counsel and Assistant Secretary of DCP Midstream, LLC since February 2000. He was previously Assistant General Counsel and Assistant Secretary at KN Energy, Inc. from December 1997 until he joined DCP Midstream, LLC. Prior to that, he was Senior Counsel and Risk Manager at Total Petroleum (North America) Ltd. from 1994 through 1997. Mr. Richards was previously in private practice where he focused on securities and corporate finance.

~~155~~
Our directors hold office for one year or until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
Thomas C. O’Connor was elected Chairman of the Board of DCP Midstream GP, LLC in September 2008, and has been a director of DCP Midstream GP, LLC since December 2007. Mr. O’Connor has over 21 years experience in the natural gas industry with Duke Energy prior to joining DCP Midstream, LLC in November 2007 as Chairman of the Board, President and CEO. Mr. O’Connor joined Duke Energy in 1987 where he served in a variety of positions in the company’s natural gas and pipeline operations units. After serving in a number of leadership positions with Duke Energy, he was named President and Chief Executive Officer of Duke Energy Gas Transmission in 2002 and he was named Group Vice President of corporate strategy at Duke Energy in 2005. In 2006 he became Group Executive and Chief Operating Officer of U.S. Franchised Electric and Gas and later in 2006 was named Group Executive and President of Commercial Businesses at Duke Energy.
Mark A. Borerwas elected President and Chief Executive Officer, and director of DCP Midstream GP, LLC in November 2006. Mr. Borer was previously Group Vice President, Marketing and Corporate Development of DCP Midstream, LLC since July 2004. He previously served as Executive Vice President of Marketing and Corporate Development of DCP Midstream, LLC from May 2002 through July 2004. Mr. Borer served as Senior Vice President, Southern Division of DCP Midstream, LLC from April 1999 through May 2002. Prior to that time, Mr. Borer was Vice President of Natural Gas Marketing for Union Pacific Fuels, Inc. Mr. Borer was a director of the general partner of TEPPCO Partners, L.P. from April 2000 until his resignation in 2005.
Angela A. Minaswas elected Vice President and Chief Financial Officer of DCP Midstream GP, LLC in September 2008. Ms. Minas was previously Chief Financial Officer, Chief Accounting Officer and Treasurer for Constellation Energy Partners from September 2006 through March 2008. She also served as Managing Director of the Commodities Group at Constellation Energy Group, Inc. from September 2006 through March 2008. Prior to that, Ms. Minas was Senior Vice President, Global Consulting from 2004 to 2006 for SAIC and Vice President, US Consulting from 2002 to 2003 for SAIC. Prior to that, Ms. Minas was a partner with Arthur Andersen LLP from 1997 through 2002.
Michael S. Richardswas elected Vice President, General Counsel and Secretary of DCP Midstream GP, LLC in September 2005. Mr. Richards was previously Assistant General Counsel and Assistant Secretary of DCP Midstream, LLC since February 2000. He was previously Assistant General Counsel and Assistant Secretary at KN Energy, Inc. from December 1997 until he joined DCP Midstream, LLC. Prior to that, he was Senior Counsel and Risk Manager at Total Petroleum (North America) Ltd. from 1994 through 1997. Mr. Richards was previously in private practice where he focused on securities and corporate finance.
Don Baldridgewas elected Vice President, Business Development of DCP Midstream GP, LLC in January 2009. Mr. Baldridge was previously Vice President, Corporate Development of DCP Midstream, LLC since August 2008. Prior to that, he served as senior director, corporate development and other management positions with DCP Midstream, LLC since April 2005. Mr. Baldridge has more than 1617 years experience in the energy industry, including commercial, trading and business development activities.
Paul F. Ferguson, Jr.was elected as a director of DCP Midstream GP, LLC in November 2005. Mr. Ferguson currently serves as Chairman of the Audit Committee of the board of directors. Mr. Ferguson was a member of the Compensation, Audit and special committees of the general partner of TEPPCO Partners, L.P. He served as Senior Vice President and Treasurer of Duke Energy from June 1997 to June 1998, when he retired. Mr. Ferguson served as Senior Vice President and Chief Financial Officer of PanEnergy Corp. from September 1995 to June 1997. He held various other financial positions with PanEnergy Corp. from 1989 to 1995 and served as Treasurer of Texas Eastern Corporation from 1988 to 1989. Mr. Ferguson was a director of the general partner of TEPPCO Partners, L.P. from October 2004 until his resignation in 2005.
~~Gregory J. Goff~~, was elected a director of DCP Midstream GP, LLC in October 2008, and is currently Senior Vice President, Commercial for ConocoPhillips. Previously, Mr. Goff served as President, Specialty Businesses and Business Development. From 2004 to 2006, Mr. Goff served as president of ConocoPhillips’ US Lower 48 and Latin American exploration and production business. From 2002 to 2004 Mr. Goff served as president of Europe and Asia Pacific Downstream Activities for ConocoPhillips. From 2000 to 2002 Mr. Goff served as Chairman and Managing Director of Conoco Limited in the United Kingdom. From 1998 to 2000 Mr. Goff served as managing Director and Chief Executive Officer of Conoco JET Nordic in Stockholm, Sweden.
Alan N. N.Harriswas appointed as a director of DCP Midstream GP, LLC in December 2008, effective January 1, ~~2009; at that time he was not appointed to any committee of the board of Directors.~~2009. In January 2009, the board of directors appointed Mr. Harris as Chairman toof the compensation committee of the board of directors. Mr. Harris currently serves as chief development and operations officer of Spectra Energy. Prior to Spectra Energy’s spin-off from Duke Energy in 2007, Mr. Harris served as group vice president and chief financial officer of Duke Energy Gas Transmission, or DEGT, from February 2004 and was named executive vice president of DEGT in December 2002. Mr. Harris, who joined the corporation in 1982, has served in a number of other senior management positions since that time. ~~Mr. Harris has been~~
Donald G. Hrap was appointed as a director of DCP Midstream GP, LLC in January 2011 and is currently president, Americas, for ConocoPhillips where he leads the development, operations, and services related to ConocoPhillips’ exploration and production business in the ~~energy industry~~Lower 48 Region of the US and in Latin America. Before his present position at ConocoPhillips, he was president of the Lower 48 Region and prior to that, senior vice president of Western Canada Gas. Mr. Hrap joined ConocoPhillips in 2006 through the merger with Burlington Resources, serving as senior vice president of operations for ~~over 30~~Burlington Canada. Prior to that he was vice president for the North American Division at Gulf Canada Resources, where he worked for 17 years.
John E. Lowe, was elected a director of DCP Midstream GP, LLC in October 2008, and is currently Assistant to the Chief Executive Officer for ConocoPhillips, representing the company in external relationships and assisting on special projects. Mr. Lowe was previously Executive Vice President, Exploration and ~~Production.~~Production, from 2007 to October 2008 and was Executive Vice President of Commercial in 2006. Prior to that, Mr. Lowe ~~has also~~ served ~~ConocoPhillips~~ as Executive Vice President of Planning, Strategy and Corporate ~~Affairs.~~Affairs from 2002 to 2006, and as Senior Vice President of Corporate Strategy and Development ~~and was responsible for the forward strategy, development opportunities and public relations functions of Phillips Petroleum Company. From 1999~~from 2001 to ~~2000, Mr. Lowe served as Vice President of Planning and Strategic Transactions for ConocoPhillips.~~
2002.
Frank A. McPhersonwas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. McPherson retired as Chairman and Chief Executive Officer from Kerr McGee Corporation in 1997 after a40-year career with the company. Mr. McPherson was Chairman and Chief Executive Officer of Kerr McGee from 1983 to 1997. Prior to that he served in various capacities in management of Kerr McGee. Mr. McPherson joined Kerr McGee in 1957. Mr. McPherson ~~previously~~ served on the boards of ~~Integris Health,~~ Tri Continental Corporation, Seligman Group of Mutual Funds, ConocoPhillips, Kimberly Clark Corporation, MAPCO Inc., Bank of Oklahoma, the Federal Reserve Bank of Kansas City ~~the Oklahoma State University Foundation Board of Trustees,~~and the American Petroleum ~~Institute, and~~Institute. He also served on the boards of several non-profit organizations in Oklahoma.
Thomas C. Morriswas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Morris is currently retired, having served 34 years with Phillips Petroleum Company. Mr. Morris served in various capacities with Phillips, including Vice President and Treasurer and subsequently Senior Vice President and

~~156~~
Chief Financial Officer from 1994 until his retirement in 2001. Mr. Morris served as Vice Chairman of the board of OK Mozart, is a former member of the executive board of the American Petroleum Institute finance committee and a former member of the Business Development Council of Texas A&M University.
Stephen R. Springerwas elected as a director of DCP Midstream GP, LLC in July 2007. Mr. Springer ~~has over thirty years experience in~~currently serves as chairman of the ~~energy industry.~~Special Committee of the board of Directors which addresses conflict situations. He began his career at Texas Gas Transmission Corporation, where he served in a variety of executive management positions within gas acquisitions and gas marketing. After serving as President of
Transco Gas Marketing Company, he served as Vice President of Business Development at Williams Field Services Company and then Senior Vice President and General Manager of Williams Midstream Division, the position he held until his retirement in 2002. Mr. Springer has served on the board of directors of Atmos Energy Corporation since 2005.

Director Experience and Qualifications
Directors are appointed annually by DCP Midstream, LLC and hold office for one year or until the earlier of their death, resignation, removal or disqualification and until their successors have been elected and qualified. DCP Midstream, LLC evaluates and recommends candidates for membership on the board of directors based on criteria established thereby. When evaluating director candidates, nominees and incumbent directors, DCP Midstream, LLC has informed us that it considers, among other things, educational background, knowledge of our business and industry, professional reputation, independence, and ability to represent the best interests of our unitholders. DCP Midstream, LLC and the board of directors believe that the above-mentioned attributes, along with the leadership skills and experience in the midstream natural gas industry, provide the Partnership with a capable and knowledgeable board of directors.
Thomas C. O’Connor — We believe Mr. O’Connor is a suitable member of the board of directors, as he brings to the company over two decades of industry experience, and has significant management experience in natural gas and pipeline transmission operations.
Mark A. Borer — We believe Mr. Borer is a suitable member of the board of directors as he brings to the company extensive industry experience. In addition, because Mr. Borer has held management positions with the company or one of its subsidiaries since 1999 and because Mr. Borer has served as a director since 2006, he brings to the board of directors, valuable historical perspective of board and company operations.
Paul F. Ferguson, Jr. — We believe that Mr. Ferguson is a suitable member of the board of directors because of his extensive industry experience. Mr. Ferguson has held various financial positions with PanEnergy Corp., and the knowledge of industry accounting and financial practices he gained through such experience, coupled with his accounting background and his CPA designation, make him valuable to the board of directors’ understanding of the Partnership’s financial data and its implications to the future strategic planning of the Partnership. Mr. Ferguson also provides insight to the board of directors as to the Partnership’s financial compliance and reporting obligations. Because Mr. Ferguson has served as a director since 2005, he brings to the board of directors, valuable historical perspective of board and company operations.
Alan N.Harris — We believe that Mr. Harris is a suitable member of the board of directors because he has over 30 years of leadership experience in the natural gas industry. In additional, Mr. Harris’ prior experience as Chief Financial Officer of DEGT and his knowledge of industry accounting and financial practices are invaluable to the board of directors’ understanding of the Partnership’s financial data and its implications to the future strategic planning of the Partnership.
Donald G. Hrap — We believe that Mr. Hrap is a suitable member of the board of directors because of his extensive executive management experience within the energy industry, in particular, his experience with ConocoPhillips and Gulf Canada, spanning over twenty years. In addition, Mr. Hrap’s experience in operations with a global energy company is valuable to company operations and future strategic planning.
John E. Lowe — We believe that Mr. Lowe is a suitable member of the board of directors because of his extensive executive management and strategic planning experience in the industry. Mr. Lowe’s prior management positions with ConocoPhillips in the corporate strategy area also provide the board with valuable insight as the board of directors moves forward with its strategic planning initiatives.
Frank A. McPherson — We believe that Mr. McPherson is a suitable member of the board of directors because of his extensive industry and executive management experience, spanning over a period of 50 years. In addition, Mr. McPherson’s prior public company board experience provides the board of directors with valuable insight into corporate governance and compliance matters. Because Mr. McPherson has served as a director since 2005, he also brings to the board of directors, valuable historical perspective of board and company operations.
Thomas C. Morris — We believe that Mr. Morris is a suitable member of the board of directors because of the industry knowledge and experience gained during his 34 years of service with Phillips Petroleum Company.
In addition, Mr. Morris’ background in finance and accounting, coupled with his previous role as Chief Financial Officer of Phillips Petroleum Company, are invaluable to the board of directors’ understanding of the Partnership’s financial data and its implications to the future strategic planning of the Partnership. Because Mr. Morris has served as a director since 2005, he also brings to the board of directors, valuable historical perspective of board and company operations.
Stephen R. Springer — We believe that Mr. Springer is a suitable member of the board of directors because of his extensive industry experience, including natural gas acquisitions, natural gas marketing, natural gas gathering and processing, NGL transportation and business development. In addition, Mr. Springer’s prior public company board experience provides the board of directors with valuable insight into public company operations, corporate governance and compliance matters.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires DCP Midstream GP, LLC’s directors and executive officers, and persons who own more than 10% of any class of our equity securities to file with the Securities and Exchange Commission, or SEC, and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of our common units and our other equity securities. Specific due dates for those reports have been established, and we are required to report herein any failure to file reports by those due dates. Directors, executive officers and greater than 10% unitholders are also required by SEC regulations to furnish us with copies of all Section 16(a) reports they file. To our knowledge, based solely on a review of the copies of reports furnished to us and written representations that no other reports were required during the fiscal year ended December 31, ~~2008,~~2010, all Section 16(a) filing requirements applicable to such reporting persons were complied ~~with, except that a late Form 4 was filed for Ms. Minas in January 2009 reflecting the granted phantom units dated October 1, 2008, following her employment by the Partnership.~~
with.
Audit Committee
The board of directors of our General Partner has a standing audit committee. The audit committee is composed of four nonmanagement directors, Paul F. Ferguson, Jr. (chairman), Frank A. McPherson, Thomas C. Morris and Stephen R. Springer, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The board has determined that each member of the audit committee is independent under Section 303A.02 of the New York Stock Exchange listing standards and Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended. In making the independence determination, the board considered the requirements of the New York Stock Exchange and our Code of Business Ethics. Among other factors, the board considered current or previous employment with us, our auditors or their affiliates by the director or his immediate family members, ownership of our voting securities, and other material relationships with us. The audit committee has adopted a charter, which has been ratified and approved by the board of directors.
With respect to material relationships, the following relationships are not considered to be material for purposes of assessing independence: service as an officer, director, employee or trustee of, or greater than five percent beneficial ownership in (a) a supplier to the partnership if the annual sales to the partnership are less than one percent of the sales of the supplier; (b) a lender to the partnership if the total amount of the partnership’s indebtedness is less than one percent of the total consolidated assets of the lender; or (c) a charitable organization if the total amount of the partnership’s annual charitable contributions to the organization are less than three percent of that organization’s annual charitable receipts.
Mr. Ferguson has been designated by the board as the audit committee’s financial expert meeting the requirements promulgated by the SEC and set forth in Item 407(d) ofRegulation S-K of the Securities Exchange Act of 1934 based upon his education and employment experience as more fully detailed in Mr. Ferguson’s biography set forth above.

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Special Committee
The board of directors of our General Partner has a standing special committee, which is comprised of four nonmanagement directors, Stephen R. Springer (chairman), Paul F. Ferguson, Jr., Frank A. McPherson and Thomas C. Morris. The special committee will review specific matters that the board believes may involve
conflicts of interest. The special committee will determine if the resolution of the conflict of interest is fair and reasonable to ~~us.~~us, or on grounds no less favorable to us than generally available from unrelated third parties. The special committee meets at each quarterly meeting of the Board of Directors. The members of the special committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates. Each of the members of the special committee meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended. Any matters approved by the special committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partner of any duties it may owe us or our unitholders.

Compensation Committee
The board of directors of our General Partner has a standing compensation committee, which is composed of four directors, Alan N. Harris (chairman), ~~Gregory J. Goff,~~John E. Lowe, Frank A. McPherson and Thomas C. ~~O’Connor and Frank A. McPherson.~~O’Connor. The compensation committee oversees compensation decisions for the officers of our general partner and administers the long-term incentive plan, selecting individuals to be granted equity-based awards from among those eligible to participate. The compensation committee has adopted a charter, which has been ratified and approved by the board of directors.

Corporate Governance Guidelines and Code of Business Ethics
Our board of directors has adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.
We have adopted a Code of Business Ethics applicable to the persons serving as our directors, officers (including without limitation, the chief executive officer, chief financial officer and principal accounting officer) and employees, which includes the prompt disclosure to the SEC of a current report onForm 8-K of any waiver of the code for executive officers or directors approved by the board of directors.
Copies of our Corporate Governance Guidelines, our Code of Business Ethics, our Audit Committee Charter and our Compensation Committee Charter are available on our website atwww.dcppartners.com. Copies of these items are also available free of charge in print to any unitholder who sends a request to the office of the Secretary of DCP Midstream Partners, LP at 370 ~~17th~~17^th Street, Suite 2775, Denver, Colorado 80202.
Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of the special committee, the committee, which consists of all of our ~~non-management~~independent directors, meets in an executive session without management participation or participation by non-independent directors. The chairman of the special committee, Stephen R. Springer, presides over these executive sessions.
In addition, at each quarterly meeting of the board of directors, the non-management members of the board meet in executive session. The chairman of the board of directors, Thomas C. O’Connor, presides over these executive sessions.
Unitholders or interested parties may communicate with any and all members of our board, including our ~~nonmanagement~~non-management directors, or any committee of our board, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board or any committee of the board at the following address and fax ~~number;~~number: Name of the Director(s),c/o Secretary, DCP Midstream Partners, LP, 370 17^th Street, Suite 2775, Denver, Colorado 80202, fax number (303) 633-2921.

New York Stock Exchange, or NYSE, Annual Certification
On ~~March 26, 2008,~~April 1, 2010, Mark A. Borer, our Chief Executive Officer, certified to the NYSE, as required by NYSE rules, that as of ~~March 26, 2008,~~April 1, 2010, he was not aware of any violation by us of the NYSE’s Corporate Governance Listing Standards.

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Report of the Audit Committee
The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the
systems of internal controls. The audit committee operates under a written charter approved by the board of directors. The charter, among other things, provides that the audit committee has authority to appoint, retain and oversee the independent auditor. In this context, the audit committee:
reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;
reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards;
• ~~reviewed and discussed the audited financial statements in this annual report onForm 10-K~~ with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;
• reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards;
• received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Deloitte & Touche, LLP;
• discussed with Deloitte & Touche, LLP its independence from management and us and considered the compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence;
• ~~discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards No. 61 (communications with audit committees);~~
• discussed with our internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting;
• ~~based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report onForm 10-K~~ ~~for the year ended December 31, 2008, for filing with the Securities and Exchange Commission; and~~
• ~~approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors.~~
received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Deloitte & Touche, LLP;
discussed with Deloitte & Touche, LLP its independence from management and us and considered the compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence;
discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards No. 61 (AICPA, Professional Standards, Vol. 1, AU Section 380—Communications With Audit Committees);
discussed with our internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting;
based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2010, for filing with the Securities and Exchange Commission; and
approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors.
This report has been furnished by the members of the audit committee of the board of directors:
Audit Committee
Paul F. Ferguson, Jr. (Chairman)
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by DCP Midstream Partners, LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.

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Item 11. Executive Compensation
Compensation Discussion and Analysis
General
As a publicly traded limited partnership, we do not have directors, officers or employees. Instead, our operations 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 our General Partner. Our General Partner is a wholly-owned subsidiary of DCP Midstream, LLC.
As of February ~~23, 2009,~~18, 2011, our General Partner ~~has~~had four named executive officers, or NEOs, and ~~six~~two additional employees. All of these employees are solely dedicated to our operations and management, except our President and Chief Executive Officer, or CEO, who devotes more than 90% of his time to our operations and management. The General Partner has not entered into employment agreements with any of our executive officers. The compensation committee of our General Partner’s board of directors establishes the compensation program for these employees.
Compensation Committee Responsibilities
The compensation committee is comprised of directors of our General Partner and has four members as of February ~~23, 2009.~~18, 2011. The compensation committee’s responsibilities include, among other duties, the following:
annually review and approve the Partnership’s goals and objectives relevant to compensation of the CEO and other NEOs;
annually evaluate the CEO’s performance in light of the Partnership’s goals and objectives, and approve the compensation levels for the CEO and other NEOs;
• ~~annually review and approve Partnership goals and objectives relevant to compensation of the CEO and other executive officers;~~
• ~~annually evaluate the CEO’s performance in light of the Partnership goals and objectives, and approve the compensation levels for the CEO and other executive officers;~~
• periodically evaluate the terms and administration of the Partnership’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with the Partnership’s goals and objectives;
• ~~periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;~~
• ~~retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and~~
• ~~perform other duties as deemed appropriate by the General Partner’s board of directors.~~
periodically evaluate the terms and administration of the Partnership’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with the Partnership’s goals and objectives;
periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or other NEO compensation; and
perform other duties as deemed appropriate by the General Partner’s board of directors.
Compensation Philosophy
Our compensation program is structured to provide the following benefits:
• ~~Attract,~~
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size or in similar lines of business;
• ~~Motivate executive officers and key management employees to achieve strong financial and operational performance;~~
• ~~Emphasize performance-based compensation, balancing short-term and long-term results;~~
• ~~Reward individual performance; and~~
• ~~Encourage a long-term commitment to the Partnership by requiring target levels of unit ownership.~~

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motivate executive officers and key management employees to achieve strong financial and operational performance;
emphasize performance-based compensation, balancing short-term and long-term results;
reward individual performance; and
encourage a long-term commitment to the Partnership by requiring target levels of unit ownership.
Methodology — Advisors and Peer Companies
~~Methodology~~
The compensation committee reviews data from market surveys provided by independent consultants to assess the competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation. With respect to ~~executive officer~~NEO compensation, the compensation committee also considers individual performance, levels of responsibility, skills and experience. In ~~2008~~2010 we engaged the services of BDO Seidman, LLP, or BDO, a compensation consultant, to conduct a study to assist us in establishing overall compensation packages for our ~~executives.~~NEOs. We consider BDO to be independent of the Partnership and therefore the work performed by BDO does not create a conflict of interest. The BDO study was based on compensation as reported in the annual reports onForm 10-K for a group of peer companies with a similar tax status, and the ~~2008~~2010 Towers ~~Perrin~~Watson General Industry Executive Compensation Database, or the Towers ~~Perrin Database.~~ Watson database.
The study was comprised of the following peer companies: Boardwalk Pipeline Partners, LP, Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., Enbridge Energy Partners, L.P., Genesis Energy, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., NuStar Energy L.P., ONEOK Partners, L.P., Plains All American Pipeline, L.P., Regency Energy Partners LP, Spectra Energy Partners, LP, Sunoco Logistics Partners L.P., Targa Resources Partners LP and TEPPCO Partners LP.
Atlas Pipeline Partners, L.P. Magellan Midstream Partners, L.P.
Boardwalk Pipeline Partners, LP MarkWest Energy Partners, L.P.
Buckeye Partners, L.P. NuStar Energy L.P.
Copano Energy, L.L.C. ONEOK Partners, L.P.
Crosstex Energy, L.P. Penn Virginia Resource Partners, L.P.
Eagle Rock Energy Partners, L.P. Plains All American Pipeline, L.P.
El Paso Pipeline Partners, L.P. Regency Energy Partners LP
Enbridge Energy Partners, L.P. Spectra Energy Partners, LP
Enterprise Products Partners L.P. Sunoco Logistics Partners L.P.
Genesis Energy, L.P. Targa Resources Partners LP
Inergy, L.P. Western Gas Partners, LP
Kinder Morgan Energy Partners, L.P. Williams Partners L.P.
Studies such as this generally include only the most highly compensated officers of each company, which correlates with our ~~executive officers.~~NEOs. The results of this study, as well as other factors such as our targeted performance objectives, served as a benchmark for establishing our total direct compensation packages. In order to assess the competitiveness of the total direct compensation packages for our ~~executive officers~~NEOs we used the median amount for peer positions from the BDO study and the data point that represents the ~~50th~~50^th percentile of the market in the Towers ~~Perrin Database.~~
Watson database.
Components of Compensation
The total annual direct compensation program for executives of the General Partner consists of three components: (1) base salary; (2) an annual short-term cash incentive, or STI, which is based on a percentage of annual base salary; and (3) the present value of an equity-based ~~cash settled~~ grant under our long-term incentive plan, or ~~LTIP.~~LTIP, which is based on a percentage of annual base salary. Under our compensation structure, the allocation between base salary, STI and LTIP varies depending upon job title and responsibility levels. In ~~2008,~~2010, this allocation for targeted compensation of our ~~executive officers~~NEOs was as follows:

Targeted
Targeted

Base Salary STI Level LTIP Level

CEO 34 % 21 % 45 %
Chief Financial Officer, or CFO 44 % 20 % 36 %
Vice Presidents 44 % 20 % 36 %
   Base
Salary Targeted
STI Level Targeted
LTIP Level
CEO
   34 % 21 % 45 %
Chief Financial Officer, or CFO
   44 % 20 % 36 %
Vice President, General Counsel & Secretary
   44 % 20 % 36 %
Vice President, Chief Development Officer
   53 % 18 % 29 %
In allocating compensation among these components, we believe a significant portion of the compensation of our executive officers should be performance-based since these individuals have a greater opportunity to influence our performance. In making this allocation, we have relied in part on the BDO study of the companies named above. Each component of compensation is further described below.

Base Salary — Base salaries for executives are determined based upon job responsibilities, level of experience, individual performance, and comparisons to the salaries of executives in similar positions obtained from the BDO study. The goal of the base salary component is to compensate executives at a level that approximates the median salaries of individuals in comparable positions at comparably sized companies in our industry.
The base salaries for executives are generally reevaluated annually as part of our performance review process, or when there is a change in the level of job responsibility. Our board of directors annually considers and approves a merit increase in base salary based upon the results of this performance review process. Merit increases are based on review of performance in certain categories, including: business values, safety, health and environment, leadership, operational results, project results, attitude, ability and knowledge. Our board of directors approved increases in NEO base salary for 2010 ranging from 3.0% to 3.2%. The base salaries paid to our ~~executive officers~~NEOs are set forth in the “Summary Compensation” table below.

Annual Short-Term Cash Incentive, or STI — Under the STI, annual cash incentives are provided to executives to promote the achievement of our performance objectives. Target incentive opportunities for
executives under the STI are established as a percentage of base salary. Incentive amounts are intended to provide total cash compensation at the market median for executive officers in comparable positions and

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markets when target performance is achieved, below the market median when performance is less than target and above the market median when performance exceeds target. The BDO study was used to determine the competitiveness of the incentive opportunity for comparable positions. STI payments are generally paid in cash in March of each year for the prior fiscal year’s performance.
In ~~2008,~~2010, the STI objectives were initially designed and proposed by the executive officers, ~~and presented to~~working with the Chairman of the General Partner’s board of ~~directors.~~directors, with objectives that are both Partnership-oriented and individually-oriented. These objectives ~~were then considered~~are intended to promote the achievement of performance objectives of the Partnership. Historically, the Partnership objectives account for 75% of the award and the personal objectives account for 25% of the award. Personal objectives typically change each year and focus on specific objectives to be targeted by each NEO for that particular calendar year. The NEOs are involved in developing these objectives because they best understand the immediate objectives required for the Partnership’s success. Nevertheless, all proposed objectives are first reviewed and revised by the Chairman of the Board for the CEO and by the CEO for the other NEOs. The CEO’s objectives are subsequently reviewed and approved by the compensation committee and ultimately by the ~~full~~General Partner’s board of directors. In ~~2008,~~2010, the STI objectives approved by the compensation committee and the General Partner’s board of directors were divided as follows: (1) ~~company~~Partnership objectives accounted for 75% of the STI and (2) personal objectives accounted for 25% of the STI. ~~The target incentive opportunities for 2008 as a percentage of base salary for the CEO, the CFO, and the Vice Presidents were 60%, 45% and 45%, respectively.~~ All STI objectives are subject to change each year.
The ~~2008 stated company objectives under the STI~~target incentive opportunities for 2010 as a percentage of base salary were ~~based on the following and were weighted~~ as ~~indicated:~~
follows:
1)   2010 Targeted
STI
Opportunity
CEO
60 %
CFO
45 %
Vice President, General Counsel & Secretary
45 %
Vice President, Chief Development Officer
35 %
For 2010 there were four stated Partnership objectives under the STI which accounted for 75% of the total STI. The stated Partnership objectives for each NEO are described below and were weighted as indicated for each NEOs:
2010 Target STI Payment Opportunity for Partnership Objectives
STI Partnership Objectives
   Mr. Borer Ms. Minas Mr. Richards Mr. Baldridge
1) Distributable Cash Flow Per Unit
   45 % 45 % 45 % 45 %
2) Total Shareholder Return vs. Peer Group
   25 % 25 % 25 % 25 %
3) Safety
   3 % 3 % 3 % 3 %
4) Environmental
   2 % 2 % 2 % 2 %

    Percentage of Total STI
   75 % 75 % 75 % 75 %
1. Distributable Cash Flow per Unit.The achievement of our budget for ~~operating~~distributable cash flow ~~from our 2008 budgeted asset base,~~per unit excluding ~~the impact from~~ non-cash ~~mark to market adjustments to derivative instruments~~mark-to-market impacts and any one-time ~~transaction~~transactions costs. We ~~define operating~~defined distributable cash flow as ~~our distributable~~net cash ~~flow plus~~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 ~~interest expense.~~income tax, net changes in operating assets and liabilities and other adjustments to reconcile net cash provided by or used in operating activities. As a publicly traded limited partnership, our performance is generally judged on our ability to pay cash distributions to our unitholders. ~~Distributable~~We use distributable cash flow ~~has three primary components: maintenance capital, interest expense and operating cash flow. We use operating cash flow as the financial objective~~per unit because we believe it ~~is the most controllable component of distributable cash flow and~~ permits management to focus on the long term sustainability and development of our assets. For this ~~company~~Partnership objective, the target level of performance is ~~operating~~distributable cash flow per unit of ~~$118.0 million,~~$3.28 per unit; the maximum level of performance is ~~operating~~distributable cash flow per unit of ~~$135.0 million and the minimum level of performance operating cash flow of $110.0 million. The weighting of this objective relative to the other stated company objectives was 35%.~~
2) Deliver on board approved 2008 growth capital including acquisitions, organic growth projects and the dropdown of assets from our sponsors. We believe that our performance is also judged by our growth, which can translate into distribution growth. For this company objective, the target level of performance is $400.0 million of approved growth capital in 2008, the maximum level of performance is $900.0 million of approved growth capital in 2008$3.96 per unit; and the minimum level of performance is ~~$250.0 million~~distributable cash flow per unit of ~~approved growth capital in 2008. The weighting of this objective relative~~$2.83 per unit.
2. Total Shareholder Return vs. Peer Group.    Maintain a competitive total shareholder return compared to the ~~other stated company objectives was 25%.~~following peer group of publicly held midstream natural gas master limited partnerships:
Copano Energy, L.L.C.
MarkWest Energy Partners, L.P.
Crestwood Midstream Partners LP
ONEOK Partners, L.P.
Duncan Energy Partners L.P.
Penn Virginia Resource Partners, L.P.
Enbridge Energy Partners, L.P.
Regency Energy Partners LP
Enterprise Products Partners L.P.
Targa Resources Partners LP
Inergy, L.P.
Western Gas Partners, LP
Final results will be based upon these companies average stock exchange closing prices for the last 20 trading days of 2009 compared to the last 20 trading days of 2010. We believe that using total shareholder return as a performance measure provides incentive for the continued growth of our operating footprint and distributions to unitholders. For this Partnership objective, the target level of performance is having a total shareholder return ranking among the companies listed in our peer group in the 50th percentile; the maximum level of performance is having a total shareholder return ranking among the companies listed in our peer group in the 90th percentile; and the minimum level of performance is having a total shareholder return ranking among the companies listed in our peer group in the 30th percentile. Total shareholder return will be based on data obtained from Bloomberg and assumes that any dividends or distributions are reinvested.
3) 3. Establishing and maintaining strong internal controls and accounting accuracy while meeting the performance requirements of the Sarbanes-Oxley Act of 2002. For this company objective, the minimum level of performance will be based on having no material weaknesses identified by management or the external auditor. A subjective determination will be made by the Audit Committee to assess performance between the minimum and maximum level of performance taking into consideration the number of significant deficiencies identified. The weighting of this objective relative to the other stated company objectives was 7%.
4) Safety Objective.    A safety objective ~~based on recordable incident rate, or RIR, of~~covering both our assets and the assets of DCP Midstream, LLC, the owner of our general partner and the operator or our ~~assets.~~assets, 70% of which is based on a recordable incident rate, or RIR, and 30% of which is based on preventable vehicle accidents, or PVAs. If a fatality occurs of our employee or that of our contractor on our premises, a 5% safety penalty will be assessed against the entire STI payout. For this ~~company~~Partnership objective, the target level of performance during the year is an RIR of 0.75 and 40 total PVAs, the maximum level of performance is an RIR of ~~0.40~~0.50 and 30 total PVAs, and the minimum level of performance is an RIR of ~~0.95. The weighting of this objective relative to the other stated company objectives was 5%.~~1.00 and 50 total PVAs.
5) 4. Environmental Objective.An environmental objective of non-routine air emissions, natural gas vented or flared, of both our assets and the assets of DCP Midstream, LLC. ~~For this company objective,~~The Partnership has established certain levels of emissions that comprise the minimum, target ~~level of~~

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~~performance is 1,000 million standard cubic feet, or MMscf, the~~and maximum level of performance ~~is 790 MMscf and the minimum level of performance is 1,200 MMscf. The weighting of~~for this ~~objective relative to the other stated company objectives was 3%.~~objective.
The payout on these ~~company~~Partnership objectives ranged from 0% if the minimum level of performance ~~was~~is not achieved, 50% if the minimum level of performance ~~was~~is achieved, 100% if the target level of performance ~~was~~is achieved and 200% if the maximum level of performance ~~was~~is achieved. When the performance level falls between these percentages, payout will be determined by straight-line interpolation.
The level of performance achieved in 2010 for each ~~objective~~of the Partnership objectives was as follows:
STI Partnership Objective

Level of
Performance Achieved
~~Level of~~
~~STI Objective~~
~~Performance Achieved~~
1) ~~Operating cash flow~~Distributable Cash Flow per Unit
   Between Minimum and Target
2) ~~Growth capital~~Total Shareholder Return vs. Peer Group
   Between Minimum and Target
3) ~~Internal controls~~
~~Target~~
4) Safety
   Between ~~Minimum~~Target and ~~Target~~Maximum
5)
4) Environmental
   ~~Below Minimum — No Payout~~Between Target and Maximum
For ~~fiscal year 2008,~~2010 the compensation committee and the board of directors adjusted the actual payout on the company objectives downward to 50% of target. In making this adjustment, we considered the current economic challenges created by the U.S. and global recession, the performance of the Partnership’s publicly traded equity and the operational challenges that were encountered by the Partnership in 2008. Taking all of these factors into consideration, we felt that it was prudent to reduce the annual cash incentives of management for these company objectives. As a result of this adjustment, the aggregate level of payout achieved for the above company objectives will be 50% of target.
~~The 2008 stated~~NEO’s personal objectives under the STI ~~were based on a number~~accounted for 25% of ~~individual performance objectives for each employee, which included items such as distribution growth, maintenance of strong liquidity in~~ the ~~debt and equity capital markets, and execution of our growth strategies.~~total STI. The personal objectives were approved by the compensation committee and the board of directors of the General Partner for the CEO, and by the CEO for the other ~~executive officers.~~ NEOs. There was overlap of the personal objectives between the NEOs. Each of the personal objectives for the NEOs and the weighting of each personal objective are described below:
2010 Target STI Payment Opportunity for Personal Objectives
STI Personal Objectives
   Mr. Borer Ms. Minas Mr. Richards Mr. Baldridge
1) Distribution Growth
   6.25 % 5 % 6.25 % 6.25 %
2) Balancing Growth
   6.25 % —    —    6.25 %
3) Enterprise Growth Plan Financing
   6.25 % —    —    6.25 %
4) Combination of #2 and #3
   —    5 % 6.25 % —
5) 2010 Business Plan
   6.25 % 5 % 6.25 % 6.25 %
6) Finance Organization Development
   —    5 % —    —
7) Internal Controls
   —    5 % —    —
8) Regulatory Compliance
   —    —    6.25 % —

    Percentage of Total STI
   25 % 25 % 25 % 25 %
1) Distribution Growth.Take action to achieve investor expectations on distribution growth.
2) Balancing Growth.Manage and adjust financial strategies and tactics to balance growth and continued near term challenges in the fundamentals and economic environment.
3) Enterprise Growth Plan Financing. Improve the Partnership’s positioning as a funding source for enterprise growth.
4) Combination of #2 and #3.This objective is a combination of objectives 2 and 3.
5) 2010 Business Plan. Take actions to achieve 2010 business plan operating results and strategic objectives.
6) Finance Organization Development. Work with DCP Midstream, LLC finance and accounting services providers to build a sustainable and high performance service delivery model for the Partnership.
7) Internal Controls. Maintain internal controls and accounting accuracy for the Partnership.
8) Regulatory Compliance. Meet all regulatory compliance requirements.
The payout on the individual personal objectives ranged from 0% if the minimum level of performance ~~was~~is not achieved, 50% if the minimum level of performance ~~was~~is achieved, 100% if the target level of performance ~~was~~is achieved and 200% if the maximum level of performance ~~was~~is achieved. When the performance level falls between these percentages, payout will be determined by straight-line interpolation.
~~For fiscal year 2008,~~
Early in 2011, management prepared a report on the ~~compensation committee and the board of directors adjusted downward the actual payout on these personal objectives as a result~~achievement of the ~~U.S. and global recessions, the performance of the Partnership’s publicly traded equity and the operational challenges that were encountered by the~~ Partnership ~~in 2008. As a result of these adjustments, the aggregate level of payout achieved by the executive officers as a group on their personal objectives will be 54.5% of target.~~
~~As a result of the adjustments recommended by the compensation committee and ratified by the board of directors discussed above regarding the company~~ objectives and the personal ~~objectives,~~objectives. These results were reviewed and approved by the Compensation Committee in February 2011, including a calculation of the percentage achievement of each objective for purposes of the STI program. The total payout for the executive officers under the STI for fiscal year ~~2008~~2010 including both Partnership objectives and personal objectives ranged from ~~37.5%~~99.26% to ~~65.5%~~105.98% of target, with the CEO at ~~37.5%~~99.26%.

Long-Term Incentive Plan, or LTIP — The long-term incentive compensation program has the objective of providing a focus on long-term value creation and enhancing executive retention. Under our LTIP program, we issued phantom limited partner units to each ~~executive officer.~~NEO. Half of such phantom units are performance phantom units, or PPUs, and half are restricted phantom units, or RPUs. The PPUs will vest based upon the level of achievement of certain performance objectives over a three year performance period, or the Performance Period. The RPUs will automatically vest if the executive officer remains employed with us at the end of a three year vesting period, or the Vesting Period. We believe this program promotes retention of our executive officers, and focuses our executive officers on the goal of long-term value creation.
For ~~2008,~~2010, the PPUs have as a performance measurement of total shareholder return over the Performance Period relative to a peer group of 3112 other similar ~~public~~publicly held master limited partnerships that we believe ~~that~~ we compete

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with in the capital markets. The companies included in this peer group at the start of ~~2008~~2010 were the following: Atlas Pipeline Partners LP, Boardwalk Pipeline Partners LP, Buckeye Partners L P, Copano Energy, L.L.C., Crosstex Energy LP, Duncan Energy Partners L.P., Eagle Rock Energy Partners L P, El Paso Pipeline Partners, L.P., Enbridge Energy Partners LP, Energy Transfer Partners, L.P., Enterprise Products Partners L P, Genesis Energy LP, Global Partners LP, Hiland Partners, LP, Holly Energy Partners LP, Kinder Morgan Energy Partners LP, Magellan Midstream Partners LP, MarkWest Energy Partners LP, NuStar Energy L.P., ONEOK Partners LP, Plains All American Pipeline LP, Quicksilver Gas Services LP, Regency Energy Partners LP, Semgroup Energy Partners, L.P., Spectra Energy Partners, LP, Sunoco Logistics Partners LP, Targa Resources Partners LP, TC Pipelines LP, TEPPCO Partners LP, TransMontaigne Partners L.P. and Williams Partners L.P.
Copano Energy, L.L.C.
MarkWest Energy Partners, L.P.
Crestwood Midstream Partners LP
ONEOK Partners, L.P.
Duncan Energy Partners L.P.
Penn Virginia Resource Partners, L.P.
Enbridge Energy Partners, L.P.
Regency Energy Partners LP
Enterprise Products Partners L.P.
Targa Resources Partners LP
Inergy, L.P.
Western Gas Partners, LP
If a company originally named to the peer group is not publicly traded at the end of the Performance Period, none of its performance will be used in calculating the peer group’s total shareholder return. If there is a combination of any peer group companies during the Performance Period, the performance of the surviving entity will be used. No new companies will be added to the peer group during the Performance Period.
~~For 2008, the~~
The RPUs awarded in 2010 will vest automatically at the end of the Vesting Period provided the executive officer remains employed with us at the end of such period.
These PPU and RPU awards were granted at the first regular meeting of the General Partner’s board of ~~directors’ meeting~~directors during the first quarter of ~~2008.~~2010. The number of awards granted to our executive officers is set forth in the “Grants of Plan-Based Awards” table below. Award recipients also received the right to receive dividend equivalent rights, or DERs, on the number of units earned during the Vesting Period. The DERs on the PPUs will be paid in cash at the end of the Performance Period and the DERs on the RPUs will be paid quarterly in cash during the Vesting Period. The amount paid on the DERs will equal the quarterly distributions actually paid during the Performance Period and the Vesting Period on the number of PPUs or RPUs earned.
Our practice is to determine the dollar amount of long-term incentive compensation that we want to provide, and to then grant a number of PPUs and RPUs that have a fair market value equal to that amount on the date of grant, which is based on the closing price of our common units on the New York Stock Exchange on the date of grant. Target long-term incentive opportunities for executives under the plan are established as a percentage of base salary, using the BDO study data for individuals in comparable positions.
The target ~~2008~~2010 long-term incentive opportunities, expressed as a percentage of base salary ~~for the CEO, the CFO and the Vice Presidents~~ were ~~130%, 80% and 80%, respectively.~~
as follows:
Targeted
LTI
Opportunity
CEO
130 %
CFO
80 %
Vice President, General Counsel & Secretary
80 %
Vice President, Chief Development Officer
55 %
For the PPUs granted in ~~2008,~~2010, the performance measure is total shareholder return over the Performance Period relative to the peer group described above. This performance measure was initially designed and proposed by the executive officers and presented to the Chairman of the General Partner’s board of directors. These objectives were then considered and approved by the compensation committee and ultimately by the ~~full~~ board of ~~directors.~~directors of the General Partner. The compensation committee believes utilizing total shareholder return as a performance measure provides incentive for the continued growth of our operating footprint and distributions to unitholders. ~~This~~We believe this performance measure ~~coupled with the 2008 STI objectives to meet or exceed operating cash flow targets,~~ provides management with appropriate incentives for our disciplined and steady growth. If our total shareholder return ranking among the 31 companies listed in our peer group over the Performance Period is less than the ~~30th~~30^th percentile, 0% of the PPUs will vest. If such ranking over the Performance Period is in the ~~30th~~30^th percentile, 50% percent of the PPUs will vest. If such ranking over the Performance Period is in the ~~50th~~50^th percentile, 100% of the PPUs will vest and if such ranking over the Performance Period is in the ~~90th~~90^th percentile, 200% of the PPUs will vest. When total shareholder return falls between 30%, 50% and 90% percentiles, vesting will be determined by straight-line interpolation. Total shareholder return will be based on data obtained from Bloomberg and assumes that any dividends or distributions are reinvested.
In the event that any person other than DCP Midstream, LLCand/or an affiliate thereof becomes the beneficial owner of more than 50% of the combined voting power of the General Partner’s equity interests prior to the completion of the Performance Period, the PPUs, RPUs and related DERs will (i) be replaced with equivalent units of the new enterprise if there is no change in the recipient’s job status for twelve months or (ii) fully vest if the recipient is severed or if the recipient’s job is lower in status within twelve months of the change in control.

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In the event an award recipient’s employment is terminated after the first anniversary of the grant date for reasons of death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause, the recipient’s (i) performance units will contingently vest on a pro-rata basis for time worked over the Performance Period and final performance, measured at the end of the Performance Period, will determine the payout and (ii) time vested units will become fully vested and payable. Termination of employment for any other reason will result in the forfeiture of any unvested units.
Other Compensation— In addition, our executives are eligible to participate in other compensation programs, which include but are not limited to:
~~Phantom IPO Units~~ — In conjunction with our initial public offering, in January 2006 our General Partner’s board of directors granted phantom limited partnership units, or Phantom IPO Units, to key employees, including the executive officers. These Phantom IPO Units vested in January 2009 and were paid in common units. There was no performance condition associated with these Phantom IPO Units. Award recipients also received DERs based on the number of common units awarded, which were paid in cash on a quarterly basis from the date of the initial grant. These phantom IPO units were granted to reward those key employees and executive officers that made significant contributions to our successful initial public offering. The amounts of awards granted to our executive officers are set forth in the “Grants of Plan-Based Awards” table below.
Company Matching and Retirement Contributions to Defined Contribution Plans — ~~Employees~~Our executives may elect to participate in the DCP Midstream, LP 401(k) and Retirement Plan. Under the plan, ~~employees~~our executives may elect to defer up to 75% of their eligible compensation, or up to the limits specified by the Internal Revenue Service. We match the first 6% of eligible compensation contributed by the ~~employee~~executive to the plan. In addition, we make retirement contributions ranging from 4% to 7% of the eligible compensation of qualifying participants to the plan, based on years of service, up to the limits specified by the Internal Revenue Service. We have no defined benefit plans.
Miscellaneous Compensation — Our executive officers are eligible to participate in a nonqualified deferred compensation program. Executive officers are allowed to defer up to 75% of their base salary, and up to 100% of their STI, LTIP or other compensation. Executive officers elect either to receive amounts contributed during specific plan years as a lump sum at a specific date, subject to Internal Revenue Service rules, or in a lump sum or annual annuity (over three to 20ten years) at termination.
Executive officers and other eligible employees may participate in a nonqualified, defined contribution retirement plan. Benefits earned under this plan are attributable to compensation in excess of the annual compensation limits under section 401(k) of the Internal Revenue Code. Under this plan, we make a contribution of up to 13% of eligible compensation, as defined by ~~this~~the plan, to the nonqualified deferred compensation program.
In addition, we provide our employees, including the executive officers, with a variety of health and welfare benefit programs. The health and welfare programs are intended to protect employees against catastrophic loss and promote well being. These programs include medical, wellness, pharmacy, dental, life insurance, ~~premiums,~~ and accidental death and disability. We also provide all our employees with a monthly parking pass or a pass to be used on available public transportation systems. In ~~addition,~~2011 we ~~pay~~eliminated certain perquisites we previously paid to our executives, which include items such as financial planning, club dues and an allowance towards annual physical exam expenses. ~~Finally, we provide all our employees with a monthly parking pass or a pass to be used on available public transportation systems.~~
We are a partnership and not a corporation for U.S. federal income tax purposes, and therefore, are not subject to the executive compensation tax deductible limitations of Internal Revenue Code ~~§ 162(m)~~§162(m). Accordingly, none of the compensation paid to our named executive officers is subject to the limitation.
Other
Unit Ownership Guidelines — To underscore the importance of linking executive and unitholder interests, the board of directors of our General Partner has adopted unit ownership guidelines for executive officers and key employees who are eligible to receive long-term incentive awards. To that extent, the board has established target equity ownership obligations for the various levels of executives, which have a five-year build term from

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the date the executive officer commences employment with us. Ownership is reported annually to the compensation committee. As of December 31, ~~2008,~~2010, all of our executive officers have satisfied the unit ownership guidelines or are meeting the required progression to achieve these unit ownership guidelines. As of December 31, 2010, the unit ownership guidelines for the executive officers were as follows:
   Number of
Units
~~Units~~
CEO
   28,000
CFO
   10,000
Vice Presidents
   10,000
~~Report of the~~ Compensation Committee Report
The compensation committee has reviewed and discussed with management the “Compensation Discussion and Analysis” presented above. Members of management with whom the compensation committee had discussions are the Chief Executive Officer of the General Partner and the Group Vice President and Chief Administrative Officer of DCP Midstream, LLC. In addition, the compensation committee engaged the services of BDO Seidman, LLP, ~~and~~ a compensation consultant, to conduct a study to assist us in establishing overall compensation packages for our executives. Based on this review and discussion, we recommended to the board of directors of the General Partner that the “Compensation Discussion and Analysis” referred to above be included in this annual report onForm 10-K for the year ended December 31, ~~2008.~~
2010.
Compensation Committee
Alan N. Harris (Chairman)
~~Gregory J. Goff~~
John E. Lowe
Frank A. McPherson
Thomas C. O’Connor

Executive Compensation
The following table discloses the compensation of the General Partner’s principal executive officers, principal financial officer and named executive officers, or collectively, the “executive officers”:

Change in

Nonqualified

Non-Equity
Deferred

Incentive Plan
Compensation
All Other

Name and Principal Position
Year Salary LTIP Awards(e) Compensation Earnings(f) Compensation(g) Total

Mark A. Borer(a) 2008 $ 358,538 $ (34,138 ) $ 80,671 $ 56,236 $ 126,851 $ 588,158
President and Chief
2007 $ 341,000 $ 151,763 $ 331,043 $ 36,518 $ 80,908 $ 941,232
Executive Officer
2006 $ 47,215 $ — $ 46,655 $ 45 $ 2,052 $ 95,967
Angela A. Minas(b) 2008 $ 61,923 $ 3,541 $ 18,252 $ — $ 49,199 $ 132,915
Vice President and Chief Financial Officer

Thomas E. Long(c) 2008 $ 76,168 $ (396,593 ) $ — $ (61,564 ) $ 31,955 $ (350,034 )
Vice President and
2007 $ 199,212 $ 304,402 $ 145,605 $ 1,584 $ 54,268 $ 705,071
Chief Financial Officer
2006 $ 180,000 $ 92,191 $ 133,650 $ — $ 33,182 $ 439,023
Michael S. Richards 2008 $ 181,748 $ (232,166 ) $ 52,343 $ (6,765 ) $ 65,136 $ 60,296
Vice President, General
2007 $ 172,615 $ 282,729 $ 125,903 $ 48 $ 46,431 $ 627,726
Counsel and Secretary
2006 $ 165,000 $ 88,390 $ 122,048 $ — $ 32,717 $ 408,155
Greg K. Smith(d) 2008 $ 190,970 $ (236,289 ) $ 32,226 $ (4,248 ) $ 69,620 $ 52,279
Vice President, Business
2007 $ 179,644 $ 289,184 $ 131,080 $ 866 $ 51,185 $ 651,959
Development
2006 $ 170,000 $ 89,600 $ 121,444 $ 480 $ 36,044 $ 417,568
Name and Principal Position
   Year    Salary
(c)    LTIP
Awards
(d)    Non-Equity
Incentive Plan
Compensation    All Other
Compensation
(e)    Total
Mark A. Borer
   2010       $ 382,760       $ 501,168       $ 227,943       $ 294,400       $ 1,406,271
President and Chief
   2009       $ 386,058       $ 486,420       $ 313,082       $ 272,010       $ 1,457,570
Executive Officer
   2008       $ 358,538       $ 474,334       $ 80,671       $ 126,851       $ 1,040,394
Angela A. Minas(a)
   2010       $ 241,558       $ 194,616       $ 115,200       $ 91,557       $ 642,931
Vice President and
Chief Financial Officer
   2009       $ 243,269       $ 188,538       $ 150,803       $ 115,321       $ 697,931
   2008       $ 61,923       $ 56,546       $ 18,252       $ 49,199       $ 185,920
Michael S. Richards
   2010       $ 194,144       $ 156,456       $ 90,317       $ 94,476       $ 535,393
Vice President,
General Counsel and Secretary
   2009       $ 195,673       $ 151,756       $ 116,488       $ 104,618       $ 568,535
   2008       $ 181,748       $ 147,826       $ 52,343       $ 65,136       $ 447,053
Don A. Baldridge(b)
   2010       $ 191,815       $ 106,212       $ 66,635       $ 60,743       $ 425,405
Vice President,
Business Development
   2009       $ 182,077       $ 93,666       $ 90,875       $ 45,969       $ 412,587
(a) ~~Mr. Borer’s employment with the General Partner commenced effective November 10, 2006.~~

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~~(b)~~ Ms. Minas’ employment with the General Partner commenced effective September 8, 2008.
~~(c)~~ (b) Mr. ~~Long’s~~Baldridge’s employment with the General Partner ~~terminated~~commenced effective ~~April 30, 2008.~~
~~(d)~~ January 5, 2009. Effective February 21, 2011, Mr. ~~Smith’s~~Baldridge’s employment with the General Partner terminated ~~effective January 5, 2009,~~ and he commenced employment with DCP Midstream, ~~LLC. Mr. Smith has been replaced by Don Baldridge, formerly employed by DCP Midstream, LLC.~~LLC as Vice President, Natural Gas and NGL Marketing.
(c) Actual salaries in 2009 were higher as a result of our bi-weekly payment methodology. Generally speaking we pay employees 26 times per year, or every two weeks. This methodology resulted in 27 pay periods in 2009.
~~(e)~~ (d) The amounts in this column reflect the ~~dollar amount recognized for financial statement reporting purposes~~grant date fair value of LTIP awards in accordance with the provisions of ~~Statement of Financial~~the FASB Accounting ~~Standard No. 123(R)~~Standards Codification, or ASC, 718 “Compensation—Stock Compensation”, ~~Share-Based Payment,~~ or ~~SFAS 123R, which incorporates re-measurement of~~ASC 718. PPU awards ~~for changes~~are subject to performance conditions. For PPUs granted in ~~the underlying assumptions used in prior periods, such as the unit price at the measurement date~~2010, 2009 and 2008 the performance ~~measure percentage. These amounts reflect our accounting expense and may~~conditions are between 0% if the minimum level of performance is not ~~necessarily correspond~~achieved to 200% if the ~~actual~~maximum level of performance is achieved. The maximum value ~~that will be realized by the named executives. The amounts exclude the impact of an estimated forfeiture rate under SFAS 123R, but do include the impact of forfeited awards if any~~ of the ~~named executives fail to perform~~PPUs, based on the ~~requisite service. Accordingly, the amounts may be negative due to these factors. This column reflects awards~~grant date fair value for Mark A. Borer was $501,168, $486,420 and $474,334 for units granted ~~in January 2006 related to our initial public offering,~~during 2010, 2009 and ~~awards granted in conjunction with our LTIP. See Note 14~~2008 respectively. The maximum value of the ~~Notes to Consolidated Financial Statements in Item 8, “Financial Statements~~PPUs, based on the grant date fair value for Angela A. Minas was $194,616, $188,538, and ~~Supplementary Data.”~~$56,546 for units granted during 2010, 2009 and 2008 respectively. The maximum value of the PPUs, based on the grant date fair value for Michael S. Richards was $156,456, $151,756 and $147,826 for units granted during 2010, 2009 and 2008 respectively. The maximum value of the PPUs, based on the grant date fair value for Don A. Baldridge was $106,212 and $93,666 for units granted during 2010 and 2009 respectively.
~~(f)~~ ~~Amounts in this column are also included in the “Nonqualified Deferred Compensation” table below.~~
~~(g)~~ (e) Includes DERs, company retirement and nonqualified deferred compensation program contributions by the Partnership, the value of life insurance premiums paid by the Partnership on behalf of an executive and other deminimus compensation.
Mark A. Borer, President and CEO
~~The annual base salary for Mr. Borer was $365,000 for 2008 and $341,000 for both 2007 and 2006, of which he deferred $125,488, $120,391 and $8,944 in 2008, 2007 and 2006, respectively.~~
The LTIP awards are comprised of PPUs and RPUs pursuant to the LTIP. Under the ~~2008, 2007~~2010, 2009 and ~~2006~~2008 STI, Mr. Borer’s target opportunity was 60% of his annual base salary, with the possibility of earning from 00% to 120% of his annual base salary in ~~2008,~~2010, 2009 and ~~0% to 109% of his annual base salary in 2007 and 2006,~~2008, depending on the level of performance in each of the STI objectives, which was pro rated in 2006 based upon his service period during 2006. While an employee at DCP Midstream, LLC during 2006, he received various equity grants and other compensation which are not reflected as part of the compensation attributable to his service with the Partnership.
objectives.
“All Other Compensation” includes the following:

2008 2007 2006

Company retirement contributions to defined contribution plans $ 29,900 $ 29,950 $ —
Nonqualified deferred compensation program contributions $ 50,160 $ 32,063 $ 1,945
DERs $ 44,947 $ 18,370 $ —
Life insurance premiums(a) $ 1,844 $ 1,225 $ 107
   2010    2009    2008
Company retirement contributions to defined contribution plans
   $ 31,850       $ 31,850       $ 29,900
Nonqualified deferred compensation program contributions
   $ 87,592       $ 60,158       $ 50,160
DERs
   $ 171,263       $ 176,424       $ 44,947
Life insurance premiums(a)
   $ 3,695       $ 3,578       $ 1,844
(a) Paid by the Partnership on behalf of Mr. Borer.
Angela A. Minas, Vice President and CFO
~~The annual base salary for Ms. Minas was $230,000 for 2008, of which she deferred $0 in 2008.~~
The LTIP awards are comprised of PPUs and RPUs pursuant to the LTIP. Under the 2010, 2009 and 2008 STI, Ms. Minas’ target opportunity was 45% of her annual base salary, with the possibility of earning from 0% to 90% of her annual base salary, depending on the level of performance in each of the STI objectives, which was pro rated in 2008 based upon her service period in 2008.

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“All Other Compensation” includes the following:

2008

Relocation expenses $ 41,901
Company retirement contributions to defined contribution plans $ 5,131
DERs $ 2,034
Life insurance premiums(a) $ 133
   2010    2009    2008
Relocation expenses
   $ —         $ 37,220       $ 41,901
Company retirement contributions to defined contribution plans
   $ 24,500       $ 24,187       $ 5,131
Nonqualified deferred compensation program contributions
   $ 1,965       $ —       $ —
DERs
   $ 64,312       $ 53,160       $ 2,034
Life insurance premiums(a)
   $ 780       $ 754       $ 133
(a) Paid by the Partnership on behalf of Ms. Minas.
~~Thomas E. Long, former~~Michael S. Richards, Vice President, General Counsel and ~~CFO~~Secretary
~~The annual base salary for Mr. Long was $215,000, $199,980 and $180,000 for 2008, 2007 and 2006, respectively, of which he deferred $131,070, $89,645 and $0 in 2008, 2007 and 2006, respectively.~~
The LTIP awards are comprised of Phantom IPO Units, PPUs and RPUs pursuant to the LTIP. Under the ~~2008, 2007~~2010, 2009 and ~~2006 STI, Mr. Long’s target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 90% of his annual base salary in~~ 2008 ~~and 0% to 82% of his annual base salary in 2007 and 2006, depending on the level of performance in each of the STI objectives.~~
~~“All Other Compensation” includes the following:~~

2008 2007 2006

Company retirement contributions to defined contribution plans $ 11,795 $ 28,476 $ 21,553
Nonqualified deferred compensation program contributions $ 14,796 $ — $ —
DERs $ 5,324 $ 25,075 $ 10,981
Life insurance premiums(a) $ 40 $ 717 $ 648
~~(a)~~ ~~Paid by the Partnership on behalf of Mr. Long.~~
~~Michael S. Richards, Vice President, General Counsel and Secretary~~
The annual base salary for Mr. Richards was $185,000, $172,920 and $165,000 for 2008, 2007 and 2006, respectively, of which he deferred $15,397, $3,452 and $0 in 2008, 2007 and 2006, respectively. The LTIP awards are comprised of Phantom IPO Units, PPUs and RPUs pursuant to the LTIP. Under both the 2008 and 2007 STI, Mr. Richards’ target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 90% of his annual base salary in ~~2008,~~2010, 2009 and ~~0% to 82% of his annual base salary in 2007 and 2006,~~2008, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:

2008 2007 2006

Company retirement contributions to defined contribution plans $ 23,000 $ 22,500 $ 20,891
Nonqualified deferred compensation program contributions $ 6,550 $ — $ —
DERs $ 35,020 $ 23,309 $ 10,482
Life insurance premiums(a) $ 566 $ 622 $ 594
Deminimus bonus $ — $ — $ 750
   2010    2009    2008
Company retirement contributions to defined contribution plans
   $ 26,950       $ 26,246       $ 23,000
Nonqualified deferred compensation program contributions
   $ 13,156       $ 7,795       $ 6,550
DERs
   $ 53,434       $ 69,988       $ 35,020
Life insurance premiums(a)
   $ 936       $ 589       $ 566
(a) Paid by the Partnership on behalf of Mr. Richards.
~~Greg K. Smith, former~~Don A. Baldridge, Vice President, Business Development
~~The annual base salary for Mr. Smith was $195,000, $180,030 and $170,000 for 2008, 2007 and 2006, respectively, of which he deferred $7,638, $7,186 and $6,800 in 2008, 2007 and 2006, respectively.~~
The LTIP awards are comprised of ~~Phantom IPO Units,~~ PPUs and RPUs pursuant to the LTIP. Under the ~~2008, 2007~~2010 and ~~2006~~2009 STI, Mr. ~~Smith’s~~Baldridge’s target opportunity was ~~45%~~35% of his annual base salary, with the possibility of earning

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from 0% to ~~90%~~70% of his annual base salary in ~~2008,~~2010 and ~~0% to 82% of his annual base salary in 2007 and 2006,~~2009, depending on the level of performance in each of the STI ~~objectives.~~
objectives, which was pro rated in 2009 based upon his service period in 2009.
“All Other Compensation” includes the following:

2008 2007 2006

Company retirement contributions to defined contribution plans $ 23,926 $ 23,855 $ 21,928
Nonqualified deferred compensation program contributions $ 9,265 $ 2,864 $ 2,864
DERs $ 36,030 $ 23,818 $ 10,640
Life insurance premiums(a) $ 399 $ 648 $ 612
   2010    2009
Company retirement contributions to defined contribution plans
   $ 24,174       $ 23,238
Nonqualified deferred compensation program contributions
   $ 5,531       $ —
DERs
   $ 30,637       $ 22,368
Life insurance premiums(a)
   $ 401       $ 363
(a) Paid by the Partnership on behalf of Mr. ~~Smith.~~Baldridge.
Grants of Plan-Based Awards
Following are the grants of plan-based awards during the year ended December 31, ~~2008~~2010 for the General Partner’s executive officers:

Grant Date

Fair Value

Estimated Future Payouts under Non-Equity Incentive Plan Awards (a) Estimated Future Payouts under Equity Incentive Plan Awards of LTIP

Minimum
Target
Maximum
Minimum
Target
Maximum
Awards

Name
Grant Date ($) ($) ($) (#) (#) (#) ($)

Mark A. Borer NA $ 109,500 $ 219,000 $ 438,000 — — — $ —
PPUs 2/25/2008(b) $ — $ — $ — 3,305 6,610 9,915 $ 237,167
RPUs 2/25/2008(c) $ — $ — $ — 6,610 6,610 6,610 $ 237,167
Angela A. Minas NA $ 51,750 $ 103,500 $ 207,000 — — — $ —
PPUs 2/25/2008(b) $ — $ — $ — 848 1,695 2,543 $ 28,273
RPUs 2/25/2008(c) $ — $ — $ — 1,695 1,695 1,695 $ 28,273
Michael S. Richards NA $ 41,625 $ 83,250 $ 166,500 — — — $ —
PPUs 2/25/2008(b) $ — $ — $ — 1,030 2,060 3,090 $ 73,913
RPUs 2/25/2008(c) $ — $ — $ — 2,060 2,060 2,060 $ 73,913
Greg K. Smith NA $ 43,875 $ 87,750 $ 175,500 — — — $ —
PPUs 2/25/2008(b) $ — $ — $ — 1,088 2,175 3,263 $ 78,039
RPUs 2/25/2008(c) $ — $ — $ — 2,175 2,175 2,175 $ 78,039
   Grant
Date Estimated Future Payouts under
Non-Equity Incentive Plan Awards (a)    Estimated Future Payouts under
Equity Incentive Plan Awards    Grant Date
Fair Value
of LTIP
Awards ($)
Name
   Minimum
($)    Target
($)    Maximum
($)    Minimum
(#)    Target
(#)    Maximum
(#)
Mark A. Borer
   NA $ 115,605       $ 231,210       $ 462,420       —       —       —       $ —
PPUs
   (b) $ —       $ —       $ —       3,940       7,880       15,760       $ 250,584
RPUs
   (c) $ —       $ —       $ —       7,880       7,880       7,880       $ 250,584
Angela A. Minas
   NA $ 54,743       $ 109,485       $ 218,970       —       —       —       $ —
PPUs
   (b) $ —       $ —       $ —       1,530       3,060       6,120       $ 97,308
RPUs
   (c) $ —       $ —       $ —       3,060       3,060       3,060       $ 97,308
Michael S. Richards
   NA $ 43,988       $ 87,975       $ 175,950       —       —       —       $ —
PPUs
   (b) $ —       $ —       $ —       1,230       2,460       4,920       $ 78,228
RPUs
   (c) $ —       $ —       $ —       2,460       2,460       2,460       $ 78,228
Don A. Baldridge
   NA $ 33,810       $ 67,620       $ 135,240       —       —       —       $ —
PPUs
   (b) $ —       $ —       $ —       835       1,670       3,340       $ 53,106
RPUs
   (c) $ —       $ —       $ —       1,670       1,670       1,670       $ 53,106
(a) Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for one or more of the components of the STI may be zero.
(b) The number of units shown represents units awarded under the LTIP. If minimum levels of performance are not met, then the payout may be zero.
(c) The number of units shown represents units awarded under the LTIP and these units vest at the end of the Vesting Period provided the individual is still employed by the Partnership.
The PPUs awarded on ~~February 25, 2008~~March 8, 2010 will vest in their entirety on December 31, ~~2010~~2012 if the specified performance conditions are satisfied and the RPUs awarded on ~~February 25, 2008~~March 8, 2010 will vest in their entirety on December 31, ~~2010~~2012 if the executive is still employed by the Partnership.

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Outstanding Equity Awards at Fiscal Year-End
Following are the outstanding equity awards for the General Partner’s executive officers as of December 31, ~~2008:~~

Outstanding LTIP Awards
Equity Incentive

Equity Incentive
Plan Awards:

Plan Awards:
Market Value of

Market Value of
Unearned Units
Unearned Units

Units That Have
Units That Have Not
That Have Not
That Have Not

Name
Not Vested(a) Vested(b) Vested(c) Vested(b)

Mark A. Borer — $ — 25,110 $ 238,269
Angela A. Minas — $ — 3,390 $ 31,866
Michael S. Richards 4,000 $ 37,600 12,730 $ 138,968
Greg K. Smith 4,000 $ 37,600 13,250 $ 144,416
2010:
   Outstanding LTIP Awards
Name
   Equity Incentive
Plan Awards:
Unearned Units
That Have Not
Vested(a)    Equity Incentive
Plan Awards:
Market Value of
Unearned Units
That Have Not
Vested(b)
Mark A. Borer
   88,360       $ 3,304,664
Angela A. Minas
   34,260       $ 1,281,324
Michael S. Richards
   27,570       $ 1,031,118
Don A. Baldridge
   17,320       $ 647,768
(a) ~~Phantom IPO Units~~PPUs awarded 1/3/~~2006;~~8/2010 and 3/2/2009; units vest in their entirety over a range of 0% to 200% on 1/12/31/2011and 12/31/2012, respectively, if the specified performance conditions are satisfied. RPUs awarded 3/~~2009. For additional information, see “Compensation Discussion~~8/2010 and ~~Analysis — Other Compensation — Phantom IPO Units.”~~3/2/2009, vest in their entirety on 12/31/2011 and 12/31/2012, respectively. To determine the market value, the calculation of the number of PPU’s granted on 3/8/2010, that are expected to vest, is based on assumed performance of 100%, as the previous fiscal year performance has exceeded threshold performance; the calculation of the number of PPU’s granted on 3/2/2009, that are expected to vest, is based on assumed performance of 200%, as the previous fiscal years’ performance has exceeded threshold performance.
(b) Value calculated based on the closing price of our common units at December 31, ~~2008.~~
~~(c)~~ ~~PPUs and RPUs awarded 5/5/2006, 2/26/2007 and 2/25/2008; units vest in their entirety over a range of 0% to 150% on 12/31/2008, 12/31/2009 and 12/31/~~2010, respectively, if the specified performance conditions are satisfied, except that the RPUs vest in their entirety on 12/31/2010; to determine the market value, the calculation of the number of units that are expected to vest for units granted in 2008 is based on assumed performance at 100%, for units granted in 2007 is based on assumed performance at 102%, and for units granted in 2006 is based on actual performance at 140.4%.which was $37.40.
Options Exercises and Stock Vested
~~There were no options exercised and no limited partnership units held by our~~
Following are the stock awards vested for the General Partner’s executive officers ~~that vested during~~for the year ended December 31, ~~2008.~~
2010:
   Stock Awards
Name
   Number of
Shares Acquired
on Vesting    Value Realized on
Vesting
Mark A. Borer
   6,610       $ 238,274
Angela A. Minas
   1,695       $ 61,101
Michael S. Richards
   2,060       $ 74,258
Don A. Baldridge
   —       $ —
Nonqualified Deferred Compensation
Following is the nonqualified deferred compensation for the General Partner’s executive officers for the year ended December 31, ~~2008:~~

Executive
Registrant
Aggregate Earnings
Aggregate

Contributions in
Contributions in
(Losses) in
Aggregate
Balance at

Last Fiscal
Last Fiscal
Last Fiscal
Withdrawals/
December 31,

Name
Year(a) Year(b) Year(c) Distributions 2008

Mark A. Borer $ 125,488 $ 50,160 $ 56,236 $ — $ 901,245
Thomas E. Long $ 131,070 $ 14,796 $ (61,564 ) $ (27,339 ) $ 148,337
Angela A. Minas $ — $ — $ — $ — $ —
Michael S. Richards $ 15,397 $ 6,550 $ (6,765 ) $ — $ 18,708
Greg K. Smith $ 7,638 $ 9,265 $ (4,248 ) $ — $ 44,305
2010:
Name
   Executive
Contributions
in Last Fiscal
Year(a)    Registrant
Contributions
in Last Fiscal
Year(b)    Aggregate
Earnings in
Last Fiscal
Year(c)    Aggregate
Withdrawal/
Distributions Aggregate
Balance at
December 31,
2010
Mark A. Borer
   $ 183,810       $ 87,592       $ 45,991       $ —    $ 836,410
Angela A. Minas
   $ 75,401       $ 1,965       $ 4,909       $ —    $ 97,756
Michael S. Richards
   $ 9,707       $ 13,156       $ 3,831       $ (15,770 ) $ 57,716
Don A. Baldridge
   $ —       $ 5,531       $ 509       $ —    $ 6,040
(a) ~~These amounts were included in the gross salary reported in the “Salary” column of the “Summary Compensation” table.~~
~~(b)~~ These amounts are included in the “Summary Compensation” table ~~within “All Other Compensation.”~~for the year 2010 with the exception of $75,401 for Ms. Minas, which was included in the “Summary Compensation” table for the year 2009 as it related to deferrals of 2009 STI.
~~(c)~~ (b) These amounts are included in the “Summary Compensation” table ~~as “Change in Nonqualified Deferred Compensation Earnings.”~~for the year 2010.

(c) The performance of executive officers non-qualified deferred compensation is linked to certain mutual funds or to the average rating of the BBB bond index at the election of the participant.
Potential Payments ~~Upon~~upon Termination or Change in Control
As noted above the PPU’s RPUs and the related dividend equivalent rights, or DER’s, will become payable to executive officers under certain circumstance related to termination or change in control. The General Partner has not entered into any employment agreements with any of our executive officers. There are no formal severance plans in place for any employees in the event of termination

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of employment, or a change in control of the Partnership. When an employee terminates employment with the Partnership, they are entitled to a cash payment for the amount of unused vacation hours at the date of their termination.

The following table presents PPU’s, RPU’s and DERs payable as of December 31, 2010 under certain circumstances, following termination, or a change in control:
Triggering Event
   PPUs    RPUs    DERs    Total
Mark A. Borer

Change of Control(a)
   $ 1,156,404       $ 1,394,678       $ 135,714       $ 2,686,796
Termination(b)
   $ 726,970       $ 1,110,623       $ 145,805       $ 1,983,398
Angela A. Minas

Change of Control(a)
   $ 448,431       $ 509,531       $ 52,617       $ 1,010,579
Termination (b)
   $ 281,783       $ 399,226       $ 56,515       $ 737,524
Michael S. Richards

Change of Control(a)
   $ 360,835       $ 435,093       $ 42,345       $ 838,273
Termination(b)
   $ 226,811       $ 346,416       $ 45,489       $ 618,716
Don A. Baldridge

Change of Control(a)
   $ 228,181       $ 228,181       $ 26,503       $ 482,865
Termination(b)
   $ 139,972       $ 167,981       $ 28,077       $ 336,030
(a) In the event that the recipient is severed or if the recipient’s job is lower in status within twelve months of the change of control.
(b) In the event of termination for reasons of death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause.
Compensation of Directors
General — Effective February ~~17, 2009,~~18, 2011, the board of directors of the General Partner approved a compensation package for directors who are not officers or employees of affiliates of the General Partner, or Non-Employee Directors. Members of the board who are also officers or employees of affiliates of the General Partner do not receive additional compensation for serving on the board. The board approved the payment to each Non-Employee Director of an annual compensation package containing the following: (1) a $40,000 retainer; (2) a board meeting fee of $1,250 for each board meeting attended; (3) a telephonic board and committee meeting fee of $500 for each telephonic meeting attended; and (4) an annual grant of Phantom Units that approximate $40,000 of value, awarded pursuant to the LTIP, that have a six month vesting period. The directors also receive DERs, based on the number of units awarded, which are paid in cash on a quarterly basis. The Phantom Units will be paid in units upon vesting.
Our directors will also be reimbursed for out-of-pocket expenses ~~in connection~~associated with ~~attending meetings of the~~their membership on our board of ~~directors and committees.~~directors. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.
Committees — The chairman of the audit committee of the board will receive an annual retainer of $20,000 and the members of the audit committee will receive $1,500 for each audit committee meeting attended. The chairman of the special committee of the board will likewise receive an annual retainer of $20,000 and the members of the special committee will receive $1,250 for each special committee meeting attended. Finally, the Non-Employee Director members of the compensation committee will receive $1,250 for each compensation committee meeting attended.
Following is the compensation of the General Partner’s Non-Employee Directors for the year ended December 31, ~~2008:~~

LTIP

Name
Fees Earned Awards(a) DERs Total

Paul F. Ferguson, Jr. $ 90,000 $ 5,479 $ 2,762 $ 98,241
Frank A. McPherson $ 72,500 $ 5,479 $ 2,762 $ 80,741
Thomas C. Morris $ 69,000 $ 5,479 $ 2,762 $ 77,241
Stephen R. Springer $ 89,500 $ 24,774 $ 1,475 $ 115,749
2010:
Name
   Fees Earned    LTIP
Awards(a)    DERs    Total
Paul F. Ferguson, Jr.
   $ 90,750       $ 41,340       $ 1,573       $ 133,663
Frank A. McPherson
   $ 72,500       $ 41,340       $ 1,573       $ 115,413
Thomas C. Morris
   $ 69,250       $ 41,340       $ 1,573       $ 112,163
Stephen R. Springer
   $ 90,750       $ 41,340       $ 1,573       $ 133,663
~~(a)~~ a) The amounts in this column reflect the ~~dollar amount recognized for financial statement reporting purposes,~~grant date fair value of LTIP awards in accordance with the provisions of SFAS 123R, and include amounts from awards granted in conjunction with our LTIP. See Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”ASC 718.
Mr. Ferguson is the audit committee chair and a member of the special committee.
Mr. McPherson ~~was the special committee chair until February 2008, and~~ is a member of the audit committee, the compensation committee and the ~~compensation~~special committee.
Mr. Morris is a member of the audit committee and the special committee.
Mr. Springer is the special committee chair and is a member of the audit committee.
The total aggregate grant date fair value of LTIP awards for the Non-Employee Directors for 2008 was $143,520. At December 31, 2008, Messrs. Ferguson, McPherson and Morris each had 666 Phantom IPO Units outstanding, which vested on January 3, 2009 and were paid in common units.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our units and the related transactions held by:
each person who beneficially owns 5% or more of our outstanding units as of February 25, 2011;
all of the directors of DCP Midstream GP, LLC;
• ~~each person who beneficially owns 5% or more of our outstanding units as of February 23, 2009;~~
• ~~all of the directors of DCP Midstream GP, LLC;~~
• ~~each Named Executive Officer of DCP Midstream GP, LLC; and~~
• ~~all directors and executive officers of DCP Midstream GP, LLC as a group.~~
each Named Executive Officer of DCP Midstream GP, LLC; and
all directors and executive officers of DCP Midstream GP, LLC as a group.
Percentage of total common units beneficially owned is based on ~~28,233,183~~40,486,782 common units outstanding.

Percentage of

Common
Common

Units
Units

Beneficially
Beneficially

Name of Beneficial Owner(a)
Owned Owned

DCP LP Holdings, LP(b)(1) 8,246,451 29.2 %
Kayne Anderson Capital Advisors, L.P.(c) 1,778,335 6.3 %
Barclays PLC(d) 1,666,334 5.9 %
Mark A. Borer 38,001 *
Angela A. Minas 15,000 *
Michael S. Richards 12,101 *
Don Baldridge 6,101 *
Alan N. Harris 9,842 *
Paul F. Ferguson, Jr. 6,334 *
John E. Lowe 40,001 *
Frank A. McPherson 15,666 *
Thomas C. Morris 20,667 *
Thomas C. O’Connor 8,000 *
Stephen R. Springer 1,500 *
All directors and executive officers as a group (11 persons) 173,213 *
Name of Beneficial Owner(a)
   Common
Units
Beneficially
Owned    Percentage
of Common
Units
Beneficially
Owned
DCP LP Holdings, LP(b)(1)
   11,746,451       29.01 %
Tortoise Capital Advisors L.L.C.(d)
   4,308,630       10.64 %
Kayne Anderson Capital Advisors, L.P.(c)
   3,070,624       7.58 %
Mark A. Borer
   41,393       *
Angela A. Minas
   30,613       *
Michael S. Richards
   13,463       *
Don Baldridge
   6,101       *
Donald G. Hrap
   —       *
Alan N. Harris
   9,842       *
Paul F. Ferguson, Jr.
   11,634       *
John E. Lowe
   1       *
Frank A. McPherson
   20,966       *
Thomas C. Morris
   25,967       *
Thomas C. O’Connor
   12,000       *
Stephen R. Springer
   6,800       *
All directors and executive officers as a group (12 persons)
   178,780       *
* Less than 1%.
(a) Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2775, Denver, Colorado 80202.
(b) DCP Midstream, LLC is the ultimate parent company of DCP LP Holdings, LP and may, therefore, be deemed to beneficially own the units held by DCP LP Holdings, LP. DCP Midstream, LLC disclaims beneficial ownership of all of the units owned by DCP LP Holdings, LP. The address of DCP LP Holdings, LP and DCP Midstream, LLC is 370 17th Street, Suite 2500, Denver, Colorado 80202.
(c) As set forth in a Schedule 13G filed on February ~~17, 2009.~~14, 2011. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067.
(d) As set forth in a Schedule 13G filed on ~~September 22, 2008.~~February 14, 2011. The address of ~~Barclays PLC~~Tortoise Capital Advisors L.L.C. is ~~1 Churchill Place, London, E14 5HP, England.~~11550 Ash Street, Suite 300, Leawood, Kansas 66211.

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Equity Compensation Plan Information
The following table summarizes information about our equity compensation plan as of December 31, ~~2008.~~
2010.
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights (1) Weighted-
average
exercise price
of outstanding
options,
warrants and
rights Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
(a) (b) (c)
Equity compensation plans approved by unitholders
— $ — —
Equity compensation plans not approved by unitholders
— — 710,100

~~Number of~~
~~Number of Securities~~
~~Securities to be~~
~~Remaining Available for~~
~~Issued upon~~
~~Weighted-Average~~
~~Future Issuance Under~~
~~Exercise of~~
~~Exercise Price of~~
~~Equity Compensation~~
~~Outstanding~~
~~Outstanding~~
~~Plans (Excluding~~
~~Options, Warrants~~
~~Options, Warrants~~
~~Securities Reflected in~~
~~and rights (1)~~
~~and Rights~~
~~Column (a))~~
~~(a)~~ ~~(b)~~ ~~(c)~~
~~Equity compensation plans approved by unitholders~~
Total
   —       $ —       —710,100
~~Equity compensation plans not approved by unitholders~~ — — ~~769,592~~
~~Total~~ — $ — ~~769,592~~

(1) The long-term incentive plan currently permits the grant of awards covering an aggregate of 850,000 units. For more information on our long-term incentive plan, which did not require approval by our limited partners, refer to Item 11. “Executive Compensation — Components of Compensation.”
Item 13. Certain Relationships and Related Transactions, and Director Independence
Distributions and Payments to our General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our formation, ongoing operation, and liquidation. These distributions and payments are determined by and among affiliated entities and, consequently, are not the result of arm’s-length negations.
Operational Stage:
~~Operational Stage:~~
Distributions of Available Cash to our General Partner and its affiliates
We will generally make cash distributions to the unitholders and to our General Partner, in accordance with their pro rata interest. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our General Partner will be entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target level. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level.
Payments to our General Partner and its affiliates
We reimburse DCP Midstream, LLC and its affiliates ~~$10.1~~$10.2 million per year, ~~adjusted annually by changes in the Consumer Price Index, for the provision of various general and administrative services for our benefit.~~ For further information regarding the ~~reimbursement, please~~reimbursement. Please see the “Omnibus Agreement” section below.
Withdrawal or removal of our General Partner
If our General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage:
Liquidation ~~Stage:~~
~~Liquidation~~
Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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Omnibus Agreement
The employees supporting our operations are employees of DCP Midstream, LLC. We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. ~~The fees under the Omnibus Agreement increased $0.4 million per year effective October 1, 2008, in connection with the acquisition of Michigan Pipeline & Processing, LLC, or MPP.~~ We also pay DCP Midstream, LLC an annual fee for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering.
~~Following is a summary of~~
Commencing January 2011 we extended the ~~fees we anticipate incurring in 2009 under the Omnibus Agreement and the effective date~~omnibus agreement through December 31, 2011 for ~~these fees:~~

Terms
Effective Date Fee
(Millions)

Annual fee 2006 $ 5.1
Wholesale propane logistics business November 2006 2.0
Southern Oklahoma May 2007 0.2
Discovery July 2007 0.2
Additional services August 2007 0.6
Momentum Energy Group, Inc. August 2007 1.6
Michigan Pipeline & Processing, LLC October 2008 0.4

Total $ 10.1

~~All of the fees under the Omnibus Agreement are subject to adjustment annually for changes in the Consumer Price Index.~~
$10.2 million. The Omnibus Agreement also addresses the following matters:
DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;
DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts; and
• ~~DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;~~
• DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price derivative contracts, to the extent that such credit support arrangements were in effect as of December 7, 2005 until the earlier of December 7, 2010 or when we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and
• DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts.
Our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses, with the concurrence of the special committee of DCP Midstream GP, LLC’s board of directors.
Our General Partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “Contracts with Affiliates.”
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, will be terminable by DCP Midstream, LLC at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of us, our general partner (DCP Midstream GP, LP) or our General Partner (DCP Midstream GP, LLC).

~~174~~
Competition
~~Competition~~
None of DCP Midstream, LLC ~~nor~~or any of its affiliates, including Spectra Energy and ConocoPhillips, is restricted, under either our partnership agreement or the Omnibus Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Spectra Energy and ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification
DCP Midstream, LLC agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions associated with repairing the Black Lake pipeline that are determined to be necessary as a result of the pipeline integrity testing. We anticipate repairs of approximately $0.8 million on the pipeline, which will be funded directly from Black Lake. We will not make contributions to Black Lake to cover these expenses.
In connection with our acquisition of our wholesale propane logistics business, DCP Midstream, LLC ~~agreed to indemnify us until October 31, 2009 for any claims for fines or penalties of any governmental authority for periods prior to the closing,~~ agreed to indemnify us until October 31, 2010 if certain contractual matters result in a claim, and agreed to indemnify us indefinitely for breaches of the agreement. The indemnity obligation for breach of the representations and warranties is not effective until claims exceed in the aggregate $680,000 and is subject to a maximum liability of $6.8 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisitions of East Texas and Discovery from DCP Midstream, LLC, DCP Midstream, LLC agreed to indemnify us until July 1, 2009 for any claims for fines or penalties of any governmental authority for periods prior to the closing and that are associated with certain East Texas assets that were formerly owned by Gulf South and UP Fuels, and agreed to indemnify us indefinitely for breaches of the agreement and certain existing claims. The indemnity obligation for breach of the representations and warranties is not effective until claims exceed in the aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
In connection with our acquisition of certain subsidiaries of MEG, DCP Midstream agreed to indemnify us until August 29, 2008 for any breach of the representations and warranties (except certain corporate related matters that survive indefinitely), and indefinitely for breaches of the agreement.
We have not pursued indemnification under ~~these agreements.~~
this agreement.
Contracts with Affiliates
We charge transportation fees, sell a portion of our residue gas and NGLs to, and purchase natural gas and NGLs from, DCP Midstream, LLC, ConocoPhillips, and their respective affiliates. We also purchase a portion of our propane from and market propane on behalf of Spectra Energy. Management anticipates continuing to purchase and sell these commodities to DCP Midstream, LLC, ConocoPhillips and their respective affiliates, and Spectra Energy in the ordinary course of business.
Natural Gas Gathering and Processing Arrangements
We have a fee-based contractual relationship with ConocoPhillips, which includes multiple contracts, pursuant to which ConocoPhillips has dedicated all of its natural gas production within an area of mutual interest to certain of our ~~Ada, Minden and Pelico~~ systems under multiple agreements that ~~have terms of up to five years and~~ are market based. These agreements provide for ~~the~~ gathering, processing and transportation ~~services at our Ada and Minden gathering and processing systems and the Pelico system. At our Ada gathering and processing system, we~~services. We collect fees from ConocoPhillips for gathering and compressing the natural gas from the wellhead or receipt point and for processing the natural gas at ~~the Ada~~certain of our processing ~~plant. At our Minden gathering and processing system, we~~plants. We also purchase natural gas from ConocoPhillips at the wellhead or receipt

~~175~~
point, transport the wellhead natural gas through our gathering ~~system,~~systems, treat and process the natural gas, and then sell a portion of the resulting residue natural gas and NGLs at index prices based on published index market prices. At
We sell NGLs processed at certain of our ~~Pelico system, we collect fees~~plants, and sell condensate removed from the gas gathering systems that deliver to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for ~~compression~~transportation, processing and ~~transportation services.~~ other charges from the tailgate of the respective asset.
Please read Item 1. “Business — Natural Gas Services Segment — Customers and Contracts” and Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” One of these arrangements is set forth in a natural gas gathering agreement dated June 1, 1987, as amended, between DCP Assets Holding, LP (successor to the interest of Cornerstone Natural Gas Company) and ConocoPhillips (successor to interest of Phillips Petroleum Company). We succeeded to the rights and obligations of DCP Assets Holding, LP under this agreement upon the closing of our initial public offering. Pursuant to this agreement, we receive gathering and compression fees from ConocoPhillips with respect to natural gas produced by ConocoPhillips that we gather and compress in our Ada gathering system from wells located in a designated area of mutual interest located in northern Louisiana covering approximately 54 square miles. The fees we receive are based on market rates for these types of services. To date, ConocoPhillips has drilled and connected approximately 180 wells to our Ada gathering system pursuant to this contract. This agreement expires in 2011. Please read Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Merchant Arrangements
Under our merchant arrangements, we use a subsidiary of DCP Midstream, LLC (DCP Midstream Marketing, LP) as our agent to purchase natural gas from third parties at pipeline interconnect points, as well as residue gas from certain of our ~~Minden and Ada~~ processing plants, and then resell the aggregated natural gas primarily to third parties. ~~In the case of certain industrial end-user customers, from time to time we may sell aggregated natural gas to a subsidiary of~~ DCP Midstream, LLC ~~which~~owns certain assets and is party to certain contractual relationships around our Pelico system, included in ~~turn would resell natural gas to these customers. Under these arrangements, we expect~~our Northern Louisiana system, that ~~this subsidiary~~are periodically used for the benefit of Pelico. DCP Midstream, LLC ~~would make a profit on these sales. We have also entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that requires DCP Midstream, LLC~~is able to ~~supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases~~source natural gas upstream of Pelico and ~~transports~~deliver it to ~~our~~us and is able to take natural gas from the outlet of the Pelico system ~~where we buy the~~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 ~~the~~DCP Midstream LLC’s actual acquisition cost plus any transportation service ~~charges incurred. If~~charges. Volumes that exceed our ~~Pelico system has volumes in excess of the~~ on-system demand are sold to DCP Midstream, LLC ~~will purchase the excess natural gas from us and transport it to sales points~~ at an index-based price, less a contractually agreed to marketing fee. In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential plus a fixed fuel charge and other related adjustments. We also sell our NGLs at the Minden processing plant to a subsidiary of DCP Midstream, LLC (DCP NGL Services, LP) who then transports the NGLs on the Black Lake pipeline.fees. Please read Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Propane Supply Arrangements
~~During the second quarter of 2008, we entered into~~
We have a propane supply agreement with Spectra ~~Energy. This agreement,~~Energy, effective from May 1, 2008 ~~and terminating~~through April 30, ~~2014,~~2012, which provides us propane supply at our Providence marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. ~~This contract replaces the supply provided under a contract with a third party that was terminated for non-performance during the first quarter of 2008.~~
~~Transportation Arrangements~~
~~Effective December 2005,~~On June 15, 2010, we entered into an amendment to the supply agreement to shorten the term of the agreement, which previously terminated on April 30, 2014. In consideration for shortening the term, Spectra Energy provided us with a ~~long-term, fee-based~~cash payment of $3.0 million.
In conjunction with our acquisition of Atlantic Energy on July 30, 2010, we acquired a propane supply agreement with Spectra Energy, effective from May 1, 2010 to April 30, 2012, which provides us propane supply for our Chesapeake marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 65 million gallons of propane annually.
In December 2010, Spectra Energy’s international propane supplier breached its contract with Spectra Energy by failing to make certain scheduled propane deliveries that were to be delivered to us under our
propane supply contracts with Spectra Energy. We were able to secure spot shipments on the open market at a price higher than our contract price to cover these missing deliveries. In December 2010 Spectra Energy made a $17.0 million payment to us to reimburse us for the damages we incurred for our open market purchases.
Transportation Arrangements
We also have a contractual arrangement with a subsidiary of DCP Midstream, LLC ~~(DCP NGL Services, LP)~~ that ~~provided~~provides that ~~the~~ DCP Midstream, LLC ~~subsidiary~~ will pay us to transport NGLs onover our Seabreeze ~~pipeline~~and Wilbreeze pipelines, pursuant to a fee-based ~~rate~~rates that will be applied to the volumes transported. ~~Under this agreement, we are required to reserve sufficient capacity in the Seabreeze pipeline to ensure our ability to accept up to 38,000 Bbls/d of NGLs tendered by the~~ DCP Midstream, LLC ~~subsidiary each day prior to utilizing~~is the ~~excess capacity for~~sole shipper on these pipelines under the transportation agreements.
In conjunction with our ~~own use or for that~~acquisition of ~~any~~

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~~third parties, and~~ the Wattenberg pipeline, which is part of our NGL Logistics segment, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement was effective through December 31, 2010. Effective January 1, 2011, we entered into a 10-year dedication and transportation agreement with a subsidiary ~~is required to tender all NGLs processed~~of DCP Midstream, LLC whereby certain NGL volumes produced at ~~certain plants that it owns, controls or otherwise has an obligation to market~~several of DCP Midstream, LLC’s processing facilities are dedicated for ~~others.~~ transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff.
DCP Midstream, LLC historically is also the largest shipper on the Black Lake pipeline, primarily due to the NGLs delivered to it from certain of our ~~Minden~~ processing ~~plant.~~plants. Please read Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Derivative Arrangements
We have entered into ~~long-term natural gas and crude oil swap~~commodity contracts whereby we receive a fixed price ~~for natural gas and crude oil~~ and we pay a floating price. DCP Midstream, LLC has issued parental guarantees in favor of certain counterparties to our ~~counterparties in those transactions that were in effect at the time~~commodity derivative instruments to mitigate a portion of our ~~initial public offering. With this credit support,~~collateral requirements with those counterparties. We pay DCP Midstream, LLC interest of 0.5% per annum on these outstanding guarantees. We have also entered into a short term NGL swap contracts with DCP Midstream, LLC whereby we ~~have more favorable collateral terms than~~receive a fixed price for NGLs and we ~~would have otherwise received.~~pay a floating price. For more information regarding our derivative activities and credit support provided by DCP Midstream, LLC, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
Other Agreements and Transactions with DCP Midstream, LLC
~~In December 2006,~~
On November 4, 2010, we ~~completed construction of our Wilbreeze pipeline, which connects a~~entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in Southeast Texas, for $150.0 million. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines, three natural gas processing ~~plant~~plants with recently increased processing capacity totaling 380 MMcf/d and natural gas storage assets with 9 Bcf of existing storage capacity. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our ~~Seabreeze pipeline. The project is supported by~~and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. This acquisition closed as of January 1, 2011.
On September 16, 2010, we entered into an ~~NGL product dedication~~ agreement with DCP Midstream, ~~LLC.~~
InLLC to sell certain surplus equipment with a net book value of $6.2 million, for net proceeds of $3.6 million. The surplus equipment is the ~~second quarter~~result of ~~2006,~~a consolidation of operations at our Anderson Gulch plant in the Piceance Basin. The net proceeds of $3.6 million have been distributed 75% to us and 25% to the noncontrolling interest in Collbran, based upon proportionate ownership. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises.
On June 30, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a ~~letter agreement~~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.
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 ~~make~~reimburse East Texas for certain expenditures on East Texas capital ~~contributions to us~~projects as ~~reimbursement~~defined in the Contribution Agreements. These reimbursements are for certain capital projects which ~~were forecasted to be completed prior to our initial public offering, but were not completed by that date. Pursuant to~~have commenced within three years from the ~~letter agreement,~~respective acquisition dates. DCP Midstream, LLC made capital contributions to usEast Texas for capital projects of ~~$3.4~~$13.8 million ~~during 2006~~ and ~~$0.3~~$67.5 million ~~during 2007, to reimburse us~~ for the ~~capital costs we incurred, primarily~~years ended December 31, 2010 and 2009, respectively.
DCP Midstream, LLC has issued parental guarantees for ~~growth capital projects.~~
~~In conjunction with our acquisition of a 40%~~its 49.9% limited liability company interest in ~~Discovery~~East Texas, totaling $6.0 million as of December 31, 2010, in favor of certain counterparties to processing and transportation agreements at East Texas. Concurrently, we have issued similar guarantees for our 50.1% interest.
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. 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 25% of any claims received as reimbursement of costs and lost margin, from the responsible third party or from insurance. DCP Midstream, LLC will pay 75% of costs related to the incident as a result of this agreement.
In April 2009, we entered into a thirteen year contractual arrangement with DCP Midstream, LLC in ~~July 2007,~~which we ~~entered into~~pay DCP Midstream, LLC a ~~letter agreement~~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 ~~whereby~~providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from the Southern Oklahoma system being processed at DCP Midstream, LLC’s plant through March 2022. In addition, as part of this arrangement, DCP Midstream, LLC ~~will make capital contributions to~~pays us ~~as reimbursement~~a fee for certain Discovery capital projects, which were forecasted to be completed prior to our acquisition of a 40% limited liability company interest in Discovery. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $3.8 million and $0.3 million during 2008 and 2007, respectively, to reimburse us for these capital projects, which were substantially completed in 2008.
gathering services.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of interest between the owner of our general partner and its affiliates, including DCP Midstream, LLC on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the special committee of the board of directors of our general partner, which is comprised of independent directors and acts as our conflicts committee. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:
•
approved by the conflicts committee;
• ~~approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;~~
• ~~on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or~~
• ~~fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.~~

~~177~~
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from the special committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in
our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.
In addition, our code of business ethics requires that all employees, including employees of affiliates of DCP Midstream, LLC who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us.

Director Independence
Please see Item 10. “Directors, Executive Officers and Corporate Governance” for information about the independence of our general partner’s board of directors and its committees, which information is incorporated herein by reference in its entirety.
Item 14. Principal Accounting Fees and Services
The following table presents fees for professional services rendered by Deloitte & Touche LLP, or Deloitte, our principal accountant, for the audit of our financial statements, and the fees billed for other services rendered by Deloitte:

Year Ended December 31,
Type of Fees
2008 2007
(Millions)

Audit Fees(a) $ 1.6 $ 1.9

      Year Ended December 31,
Type of Fees
   2010    2009
   (Millions)
Audit Fees (a)
   $ 1.8       $ 1.4

(a) Audit Fees are fees billed by Deloitte for professional services for the audit of our consolidated financial statements included in our annual report onForm 10-K and review of financial statements included in our quarterly reports onForm 10-Q, services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and include comfort and consent letters in connection with Securities and Exchange Commission filings and financing transactions.
For the last two fiscal years, Deloitte has not billed us for assurance and related services, unless such services were reasonably related to the performance of the audit or review of our financial statements, and are included in the table above. Deloitte has not provided any services to us over the last two fiscal years related to tax compliance, tax services and tax planning.

Audit Committee Pre-Approval Policy
The audit committee pre-approves all audit and permissible non-audit services provided by the independent auditors on acase-by-case basis. These services may include audit services, audit-related services, tax services and other services. The audit committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management or to an individual member of the audit committee. The audit committee has, however, pre-approved audit related services that do not impair the independence of the independent auditors for up to $50,000 per engagement, and up to an aggregate of $200,000 annually, provided the audit committee is notified of such audit-related services in a timely manner. The audit committee may, however, from time to time delegate its authority to any audit committee member, who will report on the independent auditor services that were approved at the next audit committee meeting.

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PART IV
Item 15. Exhibits and Financial Statement Schedules
Consolidated Financial Statements and Financial Statements Schedules included in this Item 15:
(a) ~~Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves~~
~~(b)~~   Consolidated Financial Statements of Discovery Producer Services LLC ~~and Financial Statements of DCP East Texas Holdings, LLC~~
~~(c)~~  (b) Exhibits
~~(a)~~   ~~Financial Statement Schedules~~
~~DCP MIDSTREAM PARTNERS, LP~~(a) Financial Statements
~~SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES~~

Charged to
Credit to

Balance at
Consolidated
Charged to
Consolidated
Balance at

Beginning of
Statements of
Other
Deductions/
Statements of
End of

Period Operations Accounts(a) Other Operations Period
(Millions)

December 31, 2008

Allowance for doubtful accounts $ 1.2 $ (0.5 ) $ — $ (0.1 ) $ — $ 0.6
Environmental 1.7 0.5 — (0.3 ) — 1.9
Other(b) — 2.6 — — — 2.6

$ 2.9 $ 2.6 $ — $ (0.4 ) $ — $ 5.1

December 31, 2007

Allowance for doubtful accounts $ 0.3 $ 0.8 $ 0.2 $ (0.1 ) $ — $ 1.2
Environmental 0.1 0.1 1.6 (0.1 ) — 1.7
Other(b) 0.3 — — (0.3 ) — —

$ 0.7 $ 0.9 $ 1.8 $ (0.5 ) $ — $ 2.9

December 31, 2006

Allowance for doubtful accounts $ 0.3 $ 0.3 $ — $ (0.3 ) $ — $ 0.3
Environmental 0.1 — — — — 0.1
Other(b) — 0.3 — — — 0.3

$ 0.4 $ 0.6 $ — $ (0.3 ) $ — $ 0.7

~~(a)~~ ~~Related to acquisition of certain subsidiaries of Momentum Energy Group, Inc.~~
~~(b)~~ ~~Principally consists of other contingency liabilities, which are included in other current liabilities.~~
~~(b)~~   ~~Financial Statements~~

~~179~~
Discovery Producer Services LLC

Consolidated Financial Statements

For the Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008

~~180~~
Report of Independent Registered Public Accounting Firm
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the related consolidated statements of income, members’ capital, and cash flows for each of the three years in the period ended December 31, ~~2008.~~2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Discovery Producer Services LLC at December 31, ~~2008~~2010 and ~~2007,~~2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2008,~~2010, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst ~~&Young~~& Young LLP
Tulsa, Oklahoma
~~February 23, 2009~~

~~181~~
March 1, 2011
DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED BALANCE SHEETS

December 31,
2008 2007
(In thousands)

ASSETS
Current assets:
Cash and cash equivalents $ 42,052 $ 38,509
Trade accounts receivable:
Affiliate 202 22,467
Other 1,899 5,847
Insurance receivable 3,373 5,692
Inventory 519 483
Other current assets 2,933 5,037

Total current assets 50,978 78,035
Restricted cash 3,470 6,222
Property, plant, and equipment, net 370,482 368,228

Total assets $ 424,930 $ 452,485

LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable:
Affiliate $ 3,125 $ 8,106
Other 34,779 17,617
Accrued liabilities 5,714 6,439
Other current liabilities 1,616 1,658

Total current liabilities 45,234 33,820
Noncurrent accrued liabilities 19,771 12,216
Members’ capital 359,925 406,449

Total liabilities and members’ capital $ 424,930 $ 452,485

   December 31,
   2010    2009
   (In thousands)
ASSETS
Current assets:

Cash and cash equivalents
   $ 10,230       $ 10,074
Trade accounts receivable:

Affiliate
   11,881       12,399
Other
   7,029       8,665
Insurance receivable
   2,234       4,647
Prepaid insurance
   2,769       2,484
Other current assets
   884       1,185

Total current assets
   35,027       39,454
Property, plant, and equipment, net
   356,201       364,932
Other noncurrent assets
   271       —

Total assets
   $ 391,499       $ 404,386

LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:

Accounts payable:

Affiliate
   $ 2,740       $ 1,986
Other
   14,031       12,329
Accrued liabilities
   684       1,101
Other current liabilities
   380       1,292

Total current liabilities
   17,835       16,708
Asset retirement obligations
   25,575       23,325
Other noncurrent liabilities
   —       30
Members’ capital
   348,089       364,323

Total liabilities and members’ capital
   $ 391,499       $ 404,386

See accompanying notes to consolidated financial statements.

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DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31,
2008 2007 2006
(In thousands)

Revenues:
Product sales:
Affiliate $ 207,706 $ 216,889 $ 148,385
Third-party 1,324 5,251 —
Gas and condensate transportation services:
Affiliate 782 979 3,835
Third-party 13,308 15,553 14,668
Gathering and processing services:
Affiliate 1,506 3,092 8,605
Third-party 12,709 17,767 19,473
Other revenues 3,913 1,141 2,347

Total revenues 241,248 260,672 197,313
Costs and expenses:
Product cost and shrink replacement:
Affiliate 83,576 93,722 66,890
Third-party 63,422 61,982 52,662
Operating and maintenance expenses:
Affiliate 8,836 5,579 5,276
Third-party 27,834 23,409 17,773
Depreciation and accretion 21,324 25,952 25,562
Taxes other than income 1,439 1,330 1,114
General and administrative expenses — affiliate 4,500 2,280 2,150
Other (income) expense, net (3,511 ) 534 283

Total costs and expenses 207,420 214,788 171,710

Operating income 33,828 45,884 25,603
Interest income (650 ) (1,799 ) (2,404 )
Foreign exchange (gain) loss 78 (388 ) (2,076 )

Net income $ 34,400 $ 48,071 $ 30,083

   Years Ended December 31,
   2010    2009 2008
   (In thousands)
Revenues:

Product sales:

Affiliate
   $ 157,785       $ 114,738    $ 207,706
Third-party
   58       66    1,324
Gas and condensate transportation services:

Affiliate
   322       485    782
Third-party
   21,743       20,155    13,308
Gathering and processing services:

Affiliate
   285       131    1,506
Third-party
   19,717       17,831    12,709
Other revenues
   7,496       7,613    3,913

Total revenues
   207,406       161,019    241,248
Costs and expenses:

Product cost and shrink replacement:

Affiliate
   23,401       20,235    83,576
Third-party
   64,330       52,271    63,422
Operating and maintenance expenses:

Affiliate
   11,903       9,580    8,836
Third-party
   24,474       13,865    27,834
Depreciation, amortization and accretion
   20,544       18,751    21,324
Taxes other than income
   3,016       3,263    1,439
General and administrative expenses — affiliate
   6,087       6,000    4,500
Other (income) expense, net
   2,229       10    (3,511 )

Total costs and expenses
   155,984       123,975    207,420

Operating income
   51,422       37,044    33,828
Interest income
   4       31    650
Foreign exchange loss
   —       (168 ) (78 )

Net income
   $ 51,426       $ 36,907    $ 34,400

See accompanying notes to consolidated financial statements.

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DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL

Williams

Williams
Partners
DCP Assets

Energy,
Operating
Holding,

L.L.C. LLC LP Total

Balance, December 31, 2005
$ 87,806 $ 170,532 $ 155,298 $ 413,636
Contributions 800 1,600 11,109 13,509
Distributions (10,798 ) (16,400 ) (16,400 ) (43,598 )
Net income 6,017 12,033 12,033 30,083

Balance at December 31, 2006
83,825 167,765 162,040 413,630
Contributions — — 3,920 3,920
Distributions (7,233 ) (28,270 ) (23,669 ) (59,172 )
Net income 2,602 26,241 19,228 48,071
Sale of Williams Energy, L.L.C.’s 20% interest to Williams Partners Operating LLC (79,194 ) 79,194 — —

Balance at December 31, 2007
— 244,930 161,519 406,449
Contributions — 5,700 7,376 13,076
Distributions — (56,400 ) (37,600 ) (94,000 )
Net income — 20,641 13,759 34,400

Balance at December 31, 2008
$ — $ 214,871 $ 145,054 $ 359,925

   Williams
Partners
Operating
LLC DCP
Assets
Holding,
LP Total
Balance at December 31, 2007
   244,930    161,519    406,449
Contributions
   5,700    7,376    13,076
Distributions
   (56,400 ) (37,600 ) (94,000 )
Net income
   20,641    13,759    34,400

Balance at December 31, 2008
   214,871    145,054    359,925
Contributions
   13,166    6,967    20,133
Distributions
   (30,747 ) (20,498 ) (51,245 )
Special distribution of interest earned on Tahiti escrow account to Williams Partners Operating LLC
   (1,397 ) —    (1,397 )
Net income
   22,703    14,204    36,907

Balance at December 31, 2009
   218,596    145,727    364,323

Contributions
   3,480    2,320    5,800
Distributions
   (44,076 ) (29,384 ) (73,460 )
Net income
   30,856    20,570    51,426

Balance at December 31, 2010
   $ 208,856    $ 139,233    $ 348,089

See accompanying notes to consolidated financial statements.

~~184~~
DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31,
2008 2007 2006
(In thousands)

OPERATING ACTIVITIES:
Net income $ 34,400 $ 48,071 $ 30,083
Adjustments to reconcile to cash provided by operations:
Depreciation and accretion 21,324 25,952 25,562
Net loss on disposal of equipment 175 603 —
Cash provided (used) by changes in assets and liabilities:
Trade accounts receivable 26,213 (9,389 ) 26,599
Insurance receivable 2,319 6,931 (12,147 )
Inventory (36 ) 93 348
Other current assets 2,104 (802 ) (1,911 )
Accounts payable 5,932 (7,540 ) (6,062 )
Accrued liabilities (725 ) 1,320 (1,086 )
Other current liabilities (52 ) (3,147 ) 2,070

Net cash provided by operating activities 91,654 62,092 63,456
INVESTING ACTIVITIES:
Decrease in restricted cash 2,752 22,551 15,786
Property, plant, and equipment:
Capital expenditures (16,188 ) (31,739 ) (33,516 )
Proceeds from sale of property, plant and equipment — 649 —
Change in accounts payable — capital expenditures 6,249 2,625 568

Net cash used by investing activities (7,187 ) (5,914 ) (17,162 )
FINANCING ACTIVITIES:
Distributions to members (94,000 ) (59,172 ) (43,598 )
Capital contributions 13,076 3,920 13,509

Net cash used by financing activities (80,924 ) (55,252 ) (30,089 )

Increase in cash and cash equivalents 3,543 926 16,205
Cash and cash equivalents at beginning of period 38,509 37,583 21,378

Cash and cash equivalents at end of period $ 42,052 $ 38,509 $ 37,583

   Years Ended December 31,
   2010 2009 2008
   (In thousands)
OPERATING ACTIVITIES:

Net income
   $ 51,426    $ 36,907    $ 34,400
Adjustments to reconcile to cash provided by operations:

Depreciation, amortization and accretion
   20,544    18,751    21,324
Net loss on disposal of equipment
   3    —    175
Cash provided (used) by changes in assets and liabilities:

Trade accounts receivable
   2,154    (18,963 ) 26,213
Insurance receivable
   2,413    (1,274 ) 2,319
Prepaid insurance
   (285 ) 216    (267 )
Other current assets
   301    (433 ) 2,335
Accounts payable
   1,372    (14,124 ) 5,932
Accrued liabilities
   (417 ) (4,613 ) (725 )
Other current liabilities
   (942 ) (383 ) (52 )

Net cash provided by operating activities
   76,569    16,084    91,654
INVESTING ACTIVITIES:

Property, plant, and equipment—capital expenditures
   (8,474 ) (19,023 ) (9,939 )
Decrease in restricted cash
   —    3,470    2,752
Acquisition of other noncurrent assets
   (279 ) —    —

Net cash used by investing activities
   (8,753 ) (15,553 ) (7,187 )
FINANCING ACTIVITIES:

Distributions to members
   (73,460 ) (52,642 ) (94,000 )
Capital contributions
   5,800    20,133    13,076

Net cash used by financing activities
   (67,660 ) (32,509 ) (80,924 )

Increase (decrease) in cash and cash equivalents
   156    (31,978 ) 3,543
Cash and cash equivalents at beginning of period
   10,074    42,052    38,509

Cash and cash equivalents at end of period
   $ 10,230    $ 10,074    $ 42,052

See accompanying notes to consolidated financial statements.

~~185~~
DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.
Organization and Description ~~of Business~~
~~Our company consists~~ of Business
Unless the context clearly indicates otherwise, references in this report to “we”, “our”, “us” or similar language refer to Discovery Producer Services LLC ~~(DPS)~~and its wholly owned subsidiary, Discovery Gas Transmission LLC (DGT). We are a Delaware limited liability company formed on June 24, 1996 ~~and its wholly owned subsidiary, Discovery Gas Transmission LLC (DGT) a Delaware limited liability company also formed on June 24, 1996. DPS was formed~~ for the purpose of constructing and operating a 600 million cubic feet per day(MMcf/d) cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day (bpd) natural gas liquids fractionator near Paradis, Louisiana. DGT ~~was~~is a Delaware limited liability company formed on June 24, 1996 for the purpose of constructing and operating a natural gas pipeline from offshore deep water in the Gulf of Mexico to ~~DPS’s~~our gas processing plant in Larose, Louisiana. The mainline has a design capacity of600 MMcf/d and consists of approximately 105 miles of pipe. ~~DPS has~~We have since connected several laterals to the DGT pipeline to expand ~~its~~our presence in the Gulf. ~~Herein, DPS and DGT~~
We are ~~collectively referred to in the first person as “we,” “us” or “our” and sometimes as “the Company”.~~
~~At the beginning of the periods presented, we were~~ owned ~~20% by Williams Energy, L.L.C. (a wholly owned subsidiary of The Williams Companies, Inc.), 40% by DCP Assets, LP (DCP) and 40%~~60% by Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners ~~L.P)~~L.P (WPZ)) and 40% by DCP Assets, LP (DCP). Williams ~~Energy,~~Field Services Group, L.L.C. is our operator. Herein, The Williams Companies, Inc. who controls WPZ through its general partner interest and its subsidiaries, including WPZ and Williams Field Services Group, L.L.C., are collectively referred to as “Williams.”
~~On June 28, 2007, WPZ acquired~~
We evaluated our disclosure of subsequent events through the ~~20% interest in us previously held by Williams Energy, L.L.C. Hence, at December 31, 2007, we are owned 60% by WPZ and 40% by DCP.~~
date, March 1, 2011, that our financial statements were issued.
Note 2. Summary of Significant Accounting Policies
~~Note 2.~~
~~Summary of Significant Accounting Policies~~
Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of ~~DPS~~the parent and ~~its~~our wholly owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated.
Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions used in the calculation of asset retirement obligations are, in the opinion of management, significant to the underlying amounts included in the consolidated financial statements. It is reasonably possible that future events or information could change those estimates.
Cash and Cash Equivalents. The cash and cash equivalent balance is primarily invested in funds with high-quality, ~~short term~~short-term securities and instruments that are issued or guaranteed by the U.S. government. These securities have maturities of three months or less when acquired.
Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We do not recognize an allowance for doubtful accounts at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of the customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. There was no allowance for doubtful accounts at December 31, ~~2008~~2010 and ~~2007.~~
2009.
Insurance Receivable. Hurricane Katrina damaged our pipeline and onshore facilities in 2005, and Hurricane Ike damaged the 30” mainline and an 18” lateral in 2008. Expenditures incurred for the repair of these damages ~~which are~~considered probable ~~for~~of recovery when incurred are recorded as insurance receivable. We expense

~~186~~
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
expenditures up to the insurance deductible ($6.4 million in 2008), amounts not covered by insurance ($2.0 million in 2008) and amounts subsequently determined not to be recoverable.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Prepaid Insurance. Prepaid insurance represents the unamortized balance of insurance premiums. These payments are amortized on a straight-line basis over the policy term.
Gas Imbalances. In the course of providing transportation services to customers, ~~DGT~~we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables which are recovered or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the future. ~~Imbalance receivables and payables are included in Other current assets and Other current liabilities in the Consolidated Balance Sheets.~~ Imbalance receivables are valued based on the lower of the current market prices or weighted average cost of natural gas in the system. Imbalance payables are valued at current market prices. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and the timing of delivery of gas based on operational conditions. Pursuant to a settlement with our shippers issued by the Federal Energy Regulatory Commission (FERC) on February 5, 2008, if a cash-out refund is due and payable to a shipper during any year pursuant to Transporter’s FERC Gas Tariff, shipper will be deemed to have immediately assigned its right to the refund amount to us.
~~Inventory.~~  ~~Inventory includes fractionated products at our Paradis facility and is carried at the lower of cost or market. Cost is determined based on the weighted average natural gas shrink replacement cost.~~
~~Restricted Cash.~~  Restricted cash within non-current assets relates to escrow funds contributed by our members for the construction of the Tahiti pipeline lateral expansion. The restricted cash is classified as non-current because the funds will be used to construct a long-term asset. The restricted cash is primarily invested in short-term money market accounts with financial institutions.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant and equipment. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of 25 to 35 years. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that extend the useful lives of the assets or increase their functionality are capitalized. The cost of property, plant and equipment sold or retired and the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recorded in the Consolidated Statements of Income.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of products is recognized in the period of delivery, and revenues from the gathering, transportation and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes. DGT is subject to ~~Federal Energy Regulatory Commission (FERC)~~FERC regulations, and accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering its and other third ~~parties~~parties’ regulatory proceedings, advice of counsel, estimated total exposure as discounted and risk weighted, and collection and other risks. There were no rate refund liabilities accrued at December 31, ~~2008~~2010 or ~~2007.~~
2009.
Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an individual asset or asset group basis when events or changes in circumstances indicate that, in our management’s judgment, the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying

~~187~~
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
value of the assets to determine whether the carrying value is recoverable. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial statements.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains or losses which are reflected in the Consolidated Statements of Income.
~~Note 3.~~   ~~Related Party Transactions~~
Note 3. Related Party Transactions
We have various business transactions with our members and subsidiaries and affiliates of our members. Revenues include the following:
sales to Williams of natural gas liquids (NGLs) to which we take title and excess natural gas at current market prices for the products and
processing and sales of natural gas liquids and transportation of natural gas and condensate for DCP’s affiliates, Texas Eastern Corporation and ConocoPhillips Company.
• ~~sales to Williams of NGLs to which we take title and excess gas at current market prices for the products and~~
• ~~processing and sales of natural gas liquids and transportation of gas and condensate for DCP’s affiliates, Texas Eastern Corporation and ConocoPhillips Company.~~
The following table summarizes these related-party revenues during ~~2008, 2007~~2010, 2009 and ~~2006.~~

Years Ended December 31,
2008 2007 2006
(In thousands)

Williams $ 207,782 $ 217,012 $ 148,543
Texas Eastern Corporation 1,953 3,912 12,282
ConocoPhillips 259 36 —

Total $ 209,994 $ 220,960 $ 160,825

2008.
   Years Ended December 31,
   2010    2009    2008
   (In thousands)
Williams
   $ 158,070       $ 114,869       $ 207,782
Texas Eastern Corporation
   —       190       1,953
ConocoPhillips
   322       295       259

Total
   $ 158,392       $ 115,354       $ 209,994

Product costs and shrink replacement — affiliate includes natural gas purchases from Williams for fuel and shrink requirements made at market rates at the time of purchase.
We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with Williams. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Operating and maintenance ~~expenses—~~expenses — affiliate includes the following:
•
direct payroll and employee benefit ~~costs incurred on our behalf by Williams, and~~
• ~~rental expense under a10-year~~ ~~leasing agreement for pipeline capacity through 2015 from Texas Eastern Transmission, LP (an affiliate of DCP)~~
~~Product~~ costs incurred on our behalf by Williams, and ~~shrink replacement—~~
rental expense under a 10-year leasing agreement for pipeline capacity through 2015 from Texas Eastern Transmission, LP (an affiliate ~~includes natural gas purchases from Williams for fuel and shrink requirements made at market rates at the time~~ of ~~purchase.~~DCP)
General and administrative expenses — affiliate includes a monthly operation and management fee paid to Williams to cover the cost of accounting services, computer systems and management services provided to us.

~~188~~
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and is capitalized as part of the construction costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows:

Years Ended December 31,
2008 2007 2006
(In thousands)

Capitalized labor $ 317 $ 222 $ 373
Capitalized project fee 375 651 538

$ 692 $ 873 $ 911

~~Note 4.~~   ~~Property, Plant, and Equipment~~
   Years Ended December 31,
   2010    2009    2008
   (In thousands)
Capitalized labor
   $ 295       $ 280       $ 317
Capitalized project fee
   288       312       375

   $ 583       $ 592       $ 692

DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 4. Property, Plant, and Equipment
Property, plant, and equipment consisted of the following at December 31, ~~2008~~2010 and ~~2007:~~

Estimated

Years Ended December 31, Depreciable

2008 2007 Lives
(In thousands)

Property, plant, and equipment:
Construction work in progress $ 76,302 $ 66,550
Buildings 5,054 4,950 25 — 35 years
Land and land rights 5,575 2,491 0 — 35 years
Transportation lines 305,172 311,368 25 — 35 years
Plant and other equipment 216,189 200,722 25 — 35 years

Total property, plant, and equipment 608,292 586,081
Less accumulated depreciation 237,810 217,853

Net property, plant, and equipment $ 370,482 $ 368,228

Effective July 1, 2008, we revised our estimate of the useful lives of the Larose processing plant and the regulated pipeline and gathering system. The annual depreciation expense will decrease $13 million.
2009:
   Years Ended
December 31,    Estimated
Depreciable
Lives

   2010    2009
   (In thousands)
Property, plant, and equipment:

Transportation lines
   $ 322,070       $ 320,956       25 — 35 years
Plant and other equipment
   291,367       283,001       25 — 35 years
Buildings
   5,139       5,055       25 — 35 years
Land and land rights
   7,491       5,556       0 — 35 years
Construction work in progress
   3,616       5,256

Total property, plant, and equipment
   629,683       619,824
Less accumulated depreciation
   273,482       254,892

Net property, plant, and equipment
   $ 356,201       $ 364,932

Commitments for construction and acquisition of property, plant, and equipment at Larose for ~~the Tahiti pipeline lateral expansion~~a cooling water system are ~~approximately $1.5 million~~$129 thousand at December 31, ~~2008.~~
2010.
Our asset retirement obligations relate primarily to our offshore platform and pipelines and our onshore processing and fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platform, properly abandon the offshore pipelines, remove the onshore facilities and related surface equipment and restore the surface of the property.

~~189~~
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
A rollforward of our asset retirement obligation for ~~2008~~2010 and ~~2007~~2009 is presented below.

Years Ended December 31,
2008 2007
(In thousands)

Balance at January 1 $ 12,118 $ 3,728
Accretion expense 1,082 422
Estimate revisions 3,327 7,554
Liabilities incurred 3,157 414

Balance at December 31 $ 19,684 $ 12,118

~~Note 5.~~   ~~Leasing Activities~~
   Years Ended December 31,
         2010                2009
   (In thousands)
Balance at January 1
   $ 23,325       $ 19,684
Accretion expense
   1,937       1,669
Estimate revisions
   313       396
Liabilities incurred
   —       1,576

Balance at December 31
   $ 25,575       $ 23,325

Note 5. Leasing Activities
We lease the land on which the Paradis fractionator and the Larose processing plant are located. The initial term of each lease is 20 years with renewal options for an additional 30 years. We also have a ten-year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP that includes renewal options and options to increase capacity which would also increase rentals. ~~On September 12, 2008, we filed an amendment to the capacity lease agreement increasing the leased capacity and resulting in a lease payment increase of $380,000 annually.~~ The future minimum annual rentals under these non-cancelable leases as of December 31, ~~2008~~2010 are payable as follows:

(In thousands)

2009 $ 1,241
2010 1,241
2011 1,241
2012 1,241
2013 1,241
Thereafter 2,105

$ 8,310

   (In thousands)
2011
   $ 1,241
2012
   1,245
2013
   1,245
2014
   1,245
2015
   670
Thereafter
   95

   $ 5,741

DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Total rent expense for ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, including a cancelable platform space lease and month-to-month leases, was $1.8 million, $1.8 million and $1.6 million, ~~$1.4 million~~respectively.
Note 6. Financial Instruments, Concentrations of Credit Risk and ~~$1.4 million, respectively.~~
Major Customers
~~Note 6.~~
~~Financial Instruments and Concentrations of Credit Risk~~
Financial Instruments Fair Value
We used the following methods and assumptions to estimate the fair value of financial instruments:
Cash and cash equivalents. The carrying amounts reported in the ~~consolidated balance sheets~~Consolidated Balance Sheets approximate fair value due to the short-term maturity of these instruments.
~~Restricted cash.~~  ~~The carrying amounts reported in the consolidated balance sheets approximate fair value as these instruments have interest rates approximating market.~~

2008 2007
Carrying
Fair
Carrying
Fair

Amount Value Amount Value
(In thousands)

Cash and cash equivalents $ 42,052 $ 42,052 $ 38,509 $ 38,509
Restricted cash 3,470 3,470 6,222 6,222

~~190~~
   2010    2009
   Carrying
Amount    Fair
Value    Carrying
Amount    Fair
Value
   (In thousands)
Cash and cash equivalents
   $ 10,230       $ 10,230       $ 10,074       $ 10,074
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Concentrations of Credit Risk
Our cash ~~equivalent~~equivalents balance is primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
At December 31, ~~2008,~~2010, substantially all of our customer accounts receivable result from product sales to and gas transmission services provided for our largest three customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on receivables during ~~2008~~2010 and ~~2007.~~
2009.
Major ~~Customers.~~Customers
Williams accounted for ~~approximately~~$158.1 million (76%), $114.9 million (71%), $208.0 million (86%~~), $217.0 million (83%), $149.8 million (75%~~) respectively, of our total revenues in ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. These revenues were for the sale of NGLs received as compensation under processing contracts with third-party producers.

Note 7. Rate and Regulatory Matters
Rate and Regulatory Matters. Annually, DGT files a request with the FERC for a fuel lost-and-unaccounted-for gas percentage to be allocated to shippers for the upcoming fiscal year beginning July 1. On ~~May 30, 2008,~~June 1, 2010, DGT filed to maintain alost-and-unaccounted-for percentage of zero percent until July 1, ~~2009~~2011 and to retain the ~~2007~~2009 net system gains of ~~$2.3 million~~$211 thousand that are unrelated to thelost-and-unaccounted-for gas over recovered from its shippers. By Order dated June ~~26, 2008~~24, 2010 the filing was approved. The approval was subject to a30-day protest period, which passed without protest. Similarly, we recognized net system gains of $5.4 million and $2.3 million in 2009 and 2008, respectively. As of December 31, ~~2008, and 2007,~~2010 DGT has no deferred ~~amounts of $5.5 million and $5.8 million, respectively,~~amount included ~~in current accrued liabilities~~ in the accompanying Consolidated Balance ~~Sheets. The December 31, 2008 balance includes 2008~~Sheets for unrecognized net system ~~gains. The~~gains because the system experienced a net system loss of $2.6 million for the year 2010 which was recognized on the Consolidated Income Statement. At December 31, ~~2007 balance represents amounts collected from customers pursuant to prior years’ lost and unaccounted for gas percentage and~~2009, accrued liabilities on the Consolidated Balance Sheet include an unrecognized net system ~~gains.~~
gain of $211 thousand.
On ~~October 16, 2008,~~November 12, 2010, DGT filed with the FERC ~~issued Order No. 717, implementing standards of conduct for interstate pipelines~~its annual Hurricane Mitigation and ~~marketing function employees of~~Reliability Enhancement (HMRE) surcharge adjustment. The filing proposed to reduce the ~~interstate pipeline or of the pipeline’s affiliates. The standards of conduct preclude an interstate pipeline~~HMRE surcharge from ~~any actions that might provide any of its or its affiliate’s marketing function employees with an unfair market advantage. The standards of conduct only apply~~$0.0374 per Dt to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such natural gas transmission provider’s pipeline. Currently DGT’s marketing or brokering affiliates do not conduct transmission transactions on DGT’s pipeline; therefore, the standards of conduct are not currently applicable to DGT.
On November 16, 2007, DGT filed a petition for approval of a settlement in lieu of a general rate change filing with FERC. One shipper, ExxonMobil Gas & Power Marketing Company, filed a protest. On February 5, 2008, the FERC issued an order approving the settlement as to all parties except the protesting ExxonMobil Gas & Power Marketing Company. The settlement allowed Discovery to recognize the amounts collected from customers pursuant to prior years lost and unaccounted for gas of $3.5 million. The order is now final and no longer subject to rehearing. DGT implemented the settlement rates and surcharges$0.0008 per Dt, effective January 1, ~~2008.~~
2011. In the same filing, DGT also requested authority to suspend invoicing the surcharge during the year 2011 if DGT’s HMRE Deferred Cost Account reaches a zero or credit
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
balance. The FERC approved the filing on December 29, 2010 and granted DGT the ability to suspend collection of the HMRE surcharge, provided that such suspension must be accompanied by an out-of-cycle HMRE application.
Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any material noncompliance under the various environmental laws and regulations.

~~191~~
~~DISCOVERY PRODUCER SERVICES LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. Litigation, arbitration and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

~~192~~
(b) Exhibits
~~DCP East Texas Holdings, LLC~~
~~Consolidated Financial Statements~~
~~For the Years Ended~~
~~December 31, 2008, 2007 and 2006~~

~~193~~
~~Deloitte & Touche LLP~~
~~Suite 3600~~
~~555 Seventeenth Street~~
~~Denver, CO80202-3942~~
~~USA~~
~~Tel: +1 303 292 5400~~
~~Fax: +1 303 312 4000~~
~~www.deloitte.com~~
~~INDEPENDENT AUDITORS’ REPORT~~
~~To the Board of Directors of~~
~~DCP Midstream, LLC~~
~~Denver, Colorado~~
We have audited the accompanying consolidated balance sheets of DCP East Texas Holdings, LLC (the “Company”), as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in partners’ equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As described in Note 1 to the consolidated financial statements, through July 1, 2007, the accompanying consolidated financial statements 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 the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, DCP Midstream, LLC as a whole.
~~/s/ Deloitte & Touche LLP~~
~~Denver, Colorado~~
~~March 4, 2009~~

~~194~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~CONSOLIDATED BALANCE SHEETS~~
~~(millions)~~

December 31,
2008 2007

ASSETS
Current assets:
Cash and cash equivalents $ 13.9 $ 4.8
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.4 million and $0.5 million, respectively 14.1 16.0
Affiliates 20.7 64.5
Other 1.1 0.8
Other 0.4 0.4

Total current assets 50.2 86.5
Property, plant and equipment, net 253.4 236.5

Total assets $ 303.6 $ 323.0

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade $ 25.8 $ 53.6
Affiliates 2.4 1.5
Other 0.9 2.9
Operating accrual 1.8 1.3
Capital spending accrual 5.1 2.7
Other 2.4 3.7

Total current liabilities 38.4 65.7
Deferred income taxes 1.7 1.7
Other long-term liabilities 0.6 0.5

Total liabilities 40.7 67.9
Commitments and contingent liabilities
Partners’ equity 262.9 255.1

Total liabilities and partners’ equity $ 303.6 $ 323.0

~~See Notes to Consolidated Financial Statements.~~

~~195~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~CONSOLIDATED STATEMENTS OF OPERATIONS~~
~~(millions)~~

Years Ended December 31,
2008 2007 2006

Operating revenues:
Sales of natural gas, NGLs and condensate $ 202.8 $ 179.8 $ 177.7
Sales of natural gas, NGLs and condensate to affiliates 313.7 270.9 286.6
Transportation and processing services 28.7 22.2 21.9
Transportation and processing services to affiliates 0.2 0.1 0.3
Losses from non-trading derivative activity — affiliates (0.6 ) (0.1 ) (1.1 )

Total operating revenues 544.8 472.9 485.4

Operating costs and expenses:
Purchases of natural gas and NGLs 419.7 357.8 376.0
Purchases of natural gas and NGLs from affiliates 0.1 1.1 9.3
Operating and maintenance expense 34.5 27.2 24.4
Depreciation expense 16.7 15.8 14.6
General and administrative expense 0.7 1.8 0.2
General and administrative expense — affiliate 8.5 10.3 11.3

Total operating costs and expenses 480.2 414.0 435.8

Operating income 64.6 58.9 49.6
Interest income 0.4 0.3 —

Income before income taxes 65.0 59.2 49.6
Income tax expense 0.5 0.7 1.8

Net income $ 64.5 $ 58.5 $ 47.8

~~See Notes to Consolidated Financial Statements.~~

~~196~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ EQUITY~~
~~(millions)~~

Balance, January 1, 2006
$ 194.0
Net change in parent advances (38.1 )
Net income 47.8

Balance, December 31, 2006
203.7
Net change in parent advances (17.1 )
Contributions 54.5
Distributions (44.5 )
Net income 58.5

Balance, December 31, 2007
255.1
Contributions 29.5
Distributions (86.2 )
Net income 64.5

Balance, December 31, 2008
$ 262.9

~~See Notes to Consolidated Financial Statements.~~

~~197~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~
~~(millions)~~

Year Ended December 31,
2008 2007 2006

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 64.5 $ 58.5 $ 47.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense 16.7 15.8 14.6
Deferred income taxes (0.1 ) (0.1 ) 1.8
Other, net (0.1 ) (0.1 ) 0.1
Change in operating assets and liabilities which provided (used) cash:
Accounts receivable 45.9 (50.6 ) 0.3
Accounts payable (28.7 ) 10.2 (12.6 )
Other current assets and liabilities (0.8 ) 2.9 (1.0 )
Other non-current assets and liabilities — — (0.2 )

Net cash provided by operating activities 97.4 36.6 50.8

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures (31.6 ) (24.5 ) (12.8 )
Proceeds from sales of assets — — 0.1

Net cash used in investing activities (31.6 ) (24.5 ) (12.7 )

CASH FLOWS FROM FINANCING ACTIVITIES:

Net change in parent advances — (17.1 ) (38.1 )
Distributions (86.2 ) (44.5 ) —
Contributions 29.5 54.3 —

Net cash used in financing activities (56.7 ) (7.3 ) (38.1 )

Net change in cash and cash equivalents 9.1 4.8 —
Cash and cash equivalents, beginning of period 4.8 — —

Cash and cash equivalents, end of period $ 13.9 $ 4.8 $ —

~~See Notes to Consolidated Financial Statements.~~

~~198~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~
1.   ~~Description of Business and Basis of Presentation~~
DCP East Texas Holdings, LLC, or East Texas, we, our, or us, is a joint venture formed in July 2007 engaged in the business of gathering, transporting, treating, compressing, processing, and fractionating natural gas and natural gas liquids, or NGLs. Our operations, located near Carthage, Texas, include a natural gas processing complex with a total capacity of 780 million cubic feet per day and a natural gas liquids fractionator. The facility is connected to our about 900 mile gathering system, as well as third party gathering systems. The complex is adjacent to our Carthage Hub, which delivers residue gas to interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas.
East Texas is owned 75% by DCP Midstream, LLC, or Midstream, and 25% by DCP Midstream Partners, LP, or Partners. The consolidated financial statements include the accounts of East Texas and, prior to July 1, 2007, the operations, assets and liabilities contributed to us by Midstream, or the Business. This was a transaction between entities under common control; accordingly, our financial information includes the results for all periods presented. Midstream is a joint venture owned 50% by Spectra Energy Corp (which was spun off by Duke Energy Corporation on January 2, 2007) and 50% by ConocoPhillips. As of December 31, 2008, Midstream owns an approximate 30% interest in Partners, which includes 100% of the general partner interest. Midstream is currently appointed as our operator and is responsible for~~day-to-day~~ ~~operation, maintenance and repair of our assets and the related managerial and administrative duties. East Texas does not currently, and does not expect to, have any employees.~~
The consolidated financial statements include the accounts of East Texas and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The consolidated financial statements of the Business were prepared from the separate records maintained by Midstream prior to July 1, 2007 and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Business had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising East Texas until July 1, 2007, Midstream’s contributions and distributions are shown as net change in parent advances in lieu of contributions and distributions in the consolidated statements of changes in partners’ equity. Transactions between East Texas and other Midstream operations have been identified in the consolidated financial statements as transactions between affiliates. Intercompany balances and transactions have been eliminated. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the consolidated financial statements.
2.   ~~Summary of Significant Accounting Policies~~
~~Use of Estimates~~ — Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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.
~~Cash and Cash Equivalents~~ ~~— Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.~~
~~Fair Value of Financial Instruments~~ — The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts, due to the short-term nature of these instruments. Unrealized gains and losses on non-trading derivative instruments are recorded at fair value.
~~Accounting for Risk Management Activities and Financial Instruments~~ — Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative

~~199~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings.
Our derivative activity includes normal purchase or normal sale contracts, and non-trading derivative instruments related to commodity prices. Normal purchase and normal sale contracts are accounted for under the accrual method and are reflected in the consolidated statements of operations in either sales or purchases upon settlement. Other commodity non-trading derivative instruments are accounted for under the~~mark-to-market~~ method, whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains or losses from non-trading derivative activity — affiliates during the current period.
~~Valuation~~ — When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
~~Property, Plant and Equipment~~ — Property, plant and equipment are recorded at original cost. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability of a conditional asset retirement obligation as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing~~and/or~~ ~~method of settlement are conditional on a future event that may or may not be within the control of the entity.~~
~~Long-Lived Assets~~ — We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
•   ~~significant adverse change in legal factors or business climate;~~
•   a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
•   ~~an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;~~
•   ~~significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;~~
•   ~~a significant adverse change in the market value of an asset; or~~

~~200~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
•   ~~a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.~~
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analyses from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
~~Revenue Recognition~~ — We generate the majority of our revenues from natural gas gathering, processing, compression, transportation, and fractionation of natural gas and NGLs. We realize revenues either by selling the residue natural gas and NGLs, or by receiving fees from the producers.
~~We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.~~
•   ~~Fee-based arrangements —~~Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced.
•   ~~Percent-of-proceeds~~ ~~arrangements —~~~~Underpercent-of-proceeds~~ arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either an~~agreed-upon~~ ~~percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or anagreed-upon~~ percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gas~~and/or~~ ~~the NGLs to the producer, in lieu of returning sales proceeds. Our revenues underpercent-of-proceeds~~ ~~arrangements correlate directly with the price of natural gasand/or~~ ~~NGLs.~~
•   ~~Keep-whole arrangements~~ — Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, sell the NGLs and return to the producer residue natural gas with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.
~~We recognize revenue for sales and services under the four revenue recognition criteria, as follows:~~
•   ~~Persuasive evidence of an arrangement exists —~~~~Our customary practice is to enter into a written contract, executed by both us and the customer.~~
•   ~~Delivery —~~~~Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory,~~

~~201~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.~~
•   ~~The fee is fixed or determinable~~ — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.
•   ~~Collectibility is probable —~~~~Collectibility is evaluated on acustomer-by-customer~~ basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectibility is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized until the cash is collected.
We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for non-trading derivative activity in the consolidated statements of operations as gains or losses from non-trading derivative activity — affiliates, including~~mark-to-market~~ ~~gains and losses and financial or physical settlement.~~
Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable — other as of December 31, 2008 and 2007 were imbalances totaling $1.1 million and $0.8 million, respectively. Included in the consolidated balance sheets as accounts payable — other as of December 31, 2008 and 2007 were imbalances totaling $0.9 million and $2.9 million, respectively.
~~Environmental Expenditures~~ — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments~~and/orclean-ups~~ are probable and the costs can be reasonably estimated. Environmental liabilities are included in the consolidated balances sheets as other current liabilities. There were no environmental liabilities included in the consolidated balance as of December 31, 2008 and 2007.
~~Income Taxes~~ — We are structured as a joint venture which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the joint venture and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. East Texas is a member of a consolidated group. We have calculated current and deferred income taxes as if we were a separate taxpayer.
The Texas legislature replaced their franchise tax with a margin tax system in May 2006. As of 2007, we are subject to the Texas margin tax, which is treated as an income tax. Accordingly, we recorded a deferred tax liability and related expense in 2008 and 2007, related to the temporary differences that are expected to reverse in periods when the tax will apply.

~~202~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
3.   ~~Recent Accounting Pronouncements~~
~~Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standards, or SFAS, No. 162 “The Hierarchy of Generally Accepted Accounting Principles,” or SFAS 162~~ — In May 2008, the FASB issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. SFAS 162 is effective 60 days following the Securities and Exchange Commission, or SEC’s, approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We have assessed the impact of the adoption of SFAS 162, and believe that there will be no impact on our consolidated results of operations, cash flows or financial position.
~~SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” or SFAS 161~~ — In March 2008, the FASB issued SFAS 161, which requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for us on January 1, 2009. We are in the process of assessing the impact of SFAS 161 on our disclosures, and will make the required disclosures in our December 31, 2009 consolidated financial statements.
~~SFAS No. 141(R) “Business Combinations (revised 2007),” or SFAS 141(R)~~ — In December, 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) is effective for us on January 1, 2009. As this standard will be applied prospectively upon adoption, we will account for all transactions with closing dates subsequent to the adoption date in accordance with the provisions of the standard.
~~SFAS, No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115”, or SFAS 159~~ — In February 2007, the FASB, issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 became effective for us on January 1, 2008. We have not elected the fair value option relative to any of our financial assets and liabilities which are not otherwise required to be measured at fair value by other accounting standards. Therefore, there is no effect of adoption reflected in our consolidated results of operations, cash flows or financial position.
~~SFAS No. 157, “Fair Value Measurements”, or SFAS 157 —~~~~In September 2006, the FASB issued SFAS 157, which was effective for us on January 1, 2008. SFAS 157:~~
•   ~~defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date;~~
•   ~~establishes a framework for measuring fair value;~~
•   ~~establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date;~~

~~203~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
•   ~~nullifies the guidance in Emerging Issues Task Force, or EITF,02-3,~~~~Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities~~~~, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique; and~~
•   ~~significantly expands the disclosure requirements around instruments measured at fair value.~~
Upon adoption of this standard we incorporated the marketplace participant view as prescribed by SFAS 157. Such changes included, but were not be limited to changes in valuation policies to reflect an exit price methodology, the effect of considering our own non-performance risk on the valuation of liabilities, and the effect of any change in our credit rating or standing. There has been no impact to our earnings as a result of adopting SFAS 157. All changes in our valuation methodology have been incorporated into our fair value calculations subsequent to adoption.
~~Pursuant to FASB Financial Staff Position157-2,~~ the FASB issued a partial deferral, ending on December 31, 2008, of the implementation of SFAS 157 as it relates to all non-financial assets and liabilities where fair value is the required measurement attribute by other accounting standards. While we have adopted SFAS 157 for all financial assets and liabilities effective January 1, 2008, we are in the process of assessing the impact that the adoption of SFAS 157 will have on our non-financial assets and liabilities, but do not expect a material impact on our consolidated results of operations, cash flows or financial positions upon adoption.
~~FASB FSPNo. 157-3~~ ~~“Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,” orFSP 157-3~~ ~~— In October 2008, the FASB issuedFSP 157-3,~~ which provides guidance in situations where a) observable inputs do not exist, b) observable inputs exist but only in an inactive market and c) how market quotes should be considered when assessing the relevance of observable and unobservable inputs to determine fair value.~~FSP 157-3~~ was effective upon issuance, including prior periods for which financial statements have not been issued. We believe that the financial assets that are reflected in our financial statements are transacted within active markets, and therefore, there is no effect on our consolidated results of operations, cash flows or financial positions as a result of the adoption of this FSP.
4.   ~~Agreements and Transactions with Affiliates~~
The employees supporting our operations are employees of Midstream. Costs incurred by Midstream on our behalf for salaries and benefits of operating personnel, as well as capital expenditures, maintenance and repair costs, and taxes have been directly allocated to us. Midstream also provides centralized corporate functions on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. Midstream records the accrued liabilities and prepaid expenses for most general and administrative expenses in its financial statements, including liabilities related to payroll, short and long-term incentive plans, employee retirement and medical plans, paid time off, audit, tax, insurance and other service fees. Through June 30, 2007, our share of those costs were allocated based on Midstream’s proportionate investment (consisting of property, plant and equipment, equity method investment and intangibles) compared to our investment. In management’s estimation, the allocation methodologies used through June 30, 2007 were reasonable and resulted in an allocation to us of our costs of doing business borne by Midstream.
Effective July 1, 2007, as part of the agreement with Midstream, we are required to reimburse Midstream for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs, insurance, taxes and other direct, indirect, and allocable costs and expenses incurred by Midstream on our behalf. We also pay Midstream an annual fee for centralized corporate functions performed by Midstream on our behalf, including legal, accounting, cash management, insurance administration and claims

~~204~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The agreement states that the fee for 2007 shall be $4.0 million as prorated from July 1 through December 31, 2007. For 2008, the fee was $8.3 million as adjusted for changes in the Consumer Price Index. After 2008, the fee shall be mutually agreed upon.
Prior to July 1, 2007, we had no cash balances on the consolidated balances sheets. Up to that date, all of our cash management activity was performed by Midstream on our behalf, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions with Midstream, which were recorded as parent advances and were included in parent equity on the accompanying consolidated balance sheets.
We currently, and anticipate to continue to, sell to Midstream, and purchase from and sell to ConocoPhillips, in the ordinary course of business. Midstream was a significant customer during the years ended December 31, 2008, 2007, and 2006.
Prior to December 31, 2006, we sold to and purchased from Duke Energy Corporation. On January 2, 2007, Duke Energy Corporation spun off their natural gas businesses, including their 50% ownership interest in Midstream, to Duke Energy shareholders. As a result of this transaction, Duke Energy Corporation’s 50% ownership interest in Midstream was transferred to Spectra Energy Corp. Consequently, Duke Energy Corporation is not considered a related party for reporting periods after January 2, 2007. We had no significant transactions with Spectra Energy Corp.
~~The following table summarizes transactions with affiliates:~~

Year Ended December 31,
2008 2007 2006
(Millions)

DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate $ 284.4 $ 263.2 $ 276.3
Losses from non-trading derivative activity $ 0.6 $ 0.1 $ 1.1
General and administrative expense $ 8.5 $ 10.3 $ 11.3
Duke Energy Corporation:
Sales of natural gas, NGLs and condensate $ — $ — $ 6.6
Purchases of natural gas and NGLs $ — $ — $ 0.1
ConocoPhillips:
Sales of natural gas, NGLs and condensate $ 29.3 $ 7.7 $ 3.7
Transportation and processing services $ 0.2 $ 0.1 $ 0.3
Purchases of natural gas and NGLs $ 0.1 $ 1.1 $ 9.2
~~We had accounts receivable and accounts payable with affiliates as follows:~~

December 31,
2008 2007
(Millions)

DCP Midstream LLC:
Accounts receivable $ 20.6 $ 64.5
Accounts payable $ 2.4 $ 1.5
ConocoPhillips:
Accounts receivable $ 0.1 $ —

~~205~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~Capital Project Reimbursement~~
In addition, Midstream has reimbursed us for work we performed on certain capital projects as defined in the Contribution Agreement. We received $2.3 million and $3.4 million of capital reimbursements during the years ended December 31, 2008 and 2007, respectively. These reimbursements are treated as contributions from Midstream.
~~Competition~~
Neither Midstream or Partners, nor any of their respective affiliates are restricted under the limited liability agreement from competing with us in other business opportunities, transactions, ventures, or other arrangements that may be competitive with or the same as us.
~~Indemnification~~
Effective upon closing on July 1, 2007, Midstream agreed to indemnify us until July 1, 2009 for any claims for fines or penalties of any governmental authority for periods prior to the closing and that are associated with assets that were formerly owned by Gulf South and UP Fuels, and agreed to indemnify us indefinitely for breaches of the agreement and certain existing claims. The indemnity obligation for breach of the representations and warranties is not effective until claims exceed in the aggregate $2.7 million and is subject to a maximum liability of $27.0 million. This indemnity obligation for all other claims other than a breach of the representations and warranties does not become effective until an individual claim or series of related claims exceed $50,000.
5.   ~~Property, Plant and Equipment~~
~~A summary of property, plant and equipment is as follows:~~

Depreciable
December 31,
Life 2008 2007
(Millions)

Gathering systems 15 – 30 Years $ 92.8 $ 78.9
Processing plants 25 – 30 Years 219.8 218.5
Transportation 25 – 30 Years 42.6 40.0
Underground storage 20 – 50 Years 0.1 —
General plant 3 – 5 Years 7.9 7.8
Construction work in progress 30.3 14.7

393.5 359.9
Accumulated depreciation (140.1 ) (123.4 )

Property, plant and equipment, net $ 253.4 $ 236.5

Depreciation expense for the years ended December 31, 2008, 2007 and 2006, was $16.7 million, $15.8 million and $14.6 million respectively. At December 31, 2008, we had non-cancelable purchase obligations of approximately $0.8 million for capital projects anticipated to be completed in 2009.
6.   ~~Risk Management and Derivative Activities, Credit Risk and Financial Instruments~~
The only impact of our derivative activity was losses from non-trading derivative activity — affiliates of $0.6 million, $0.1 million and $1.1 million for the years ended December 31, 2008, 2007 and 2006, respectively.

~~206~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
We are exposed to market risks, including changes in commodity prices. We may use financial instruments such as forward contracts, swaps and futures to mitigate the effects of the identified risks. In general, we attempt to mitigate risks related to the variability of future cash flows resulting from changes in applicable commodity prices. Midstream has a comprehensive risk management policy, or the Risk Management Policy, and a risk management committee, to monitor and manage market risks associated with commodity prices. Midstream’s Risk Management Policy prohibits the use of derivative instruments for speculative purposes.
~~Commodity Price Risk~~ — Our principal operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and sale of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs and natural gas. As an owner and operator of natural gas processing assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas, NGLs and condensate, and related products produced, processed or transported.
~~Credit Risk~~ — We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of Midstream, national wholesale marketers, industrial end-users and gas-fired power plants. Our principal NGL customers include an affiliate of Midstream, producers and marketing companies. Concentration of credit risk may affect our overall credit risk, in that 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 Midstream’s corporate credit policy. Midstream’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 Midstream’s 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 Midstream’s credit policy and guidelines. The agreements also provide that the inability of 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 form satisfactory to us.
~~Commodity Non-Trading Derivative Activity~~ — The sale of energy related products and services exposes us to the fluctuations in the market values of exchanged instruments. On a monthly basis, we may enter into non-trading derivative instruments in order to match the pricing terms to manage our purchase and sale portfolios. Midstream manages our marketing portfolios in accordance with their Risk Management Policy, which limits exposure to market risk.
~~Normal Purchases and Normal Sales~~ — If a contract qualifies and is designated as a normal purchase or normal sale, no recognition of the contract’s fair value in the consolidated financial statements is required until the associated delivery period impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of physical natural gas or NGLs in future periods.
7.   ~~Asset Retirement Obligations~~
~~Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related toright-of-way~~ easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the

~~207~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~obligation is settled. Accretion expense for the years ended December 31, 2008, 2007 and 2006 was not significant.~~
The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation as December 31, 2008 and 2007 included in the consolidated balance sheets as other long-term liabilities was $0.6 million and $0.5 million, respectively.
8.   ~~Income Taxes~~
In May 2006, the State of Texas enacted a margin-based franchise tax law that replaced the existing franchise tax, commonly referred to as the Texas margin tax. The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. As a result of the change in Texas franchise law, our status in the state of Texas changed from non-taxable to taxable. Since the Texas margin tax is considered an income tax, in 2006 we recorded a non-current deferred tax liability of $1.8 million. The Texas margin tax became effective for franchise tax reports due on or after January 1, 2008. The 2008 tax was based on revenues earned during the 2007 fiscal year. Accordingly, we recorded current tax expense for the Texas margin tax for 2008 and 2007 of $0.6 million and $0.8 million, respectively, and a reduction in deferred taxes of $0.1 million for both 2008 and 2007.
~~Our effective tax rate differs from statutory rates primarily due to our being treated as a pass-through entity for United States income tax purposes, while being treated as a taxable entity in Texas.~~
9.   ~~Commitments and Contingent Liabilities~~
~~Litigation~~ — We are not a party to any significant legal proceedings, but are a party to various 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 the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position, or cash flows.
~~Insurance~~ — For the period August 2006 through August 2007, Midstream’s insurance coverage was carried with an affiliate of ConocoPhillips and third party insurers. Prior to August 2006, Midstream carried a portion of their insurance coverage with an affiliate of Duke Energy Corporation. Effective in August 2007, insurance coverage is carried with third party insurers. Midstream’s insurance coverage includes: (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) excess liability insurance above the established primary limits for commercial general liability and automobile liability insurance; and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, windstorms, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.
~~A portion of the insurance costs described above are allocated by Midstream to us through the allocation methodology described in Note 4.~~
~~Environmental~~ — The operation of pipelines, plants and other facilities for gathering, transporting, processing, or treating natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and

~~208~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
~~10.~~   ~~Supplemental Cash Flow Information~~

Year Ended December 31,
2008 2007 2006
(Millions)

Non-cash investing and financing activities:
Non-cash additions of property, plant and equipment $ 2.0 $ 0.9 $ 3.1
Accrued contributions related to reimbursements $ — $ 0.2 $ —
~~11.~~   ~~Subsequent Events~~
In February 2009, we announced that our East Texas natural gas processing complex and residue natural gas delivery system known as the Carthage Hub, have been temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. No employees or contractors were injured in the incident. There was no significant damage to the natural gas processing complex. As of February 25, 2009, the complex began processing through one of the five plants, and it is expected that full processing capacities will be restored for the entire complex over the next 30 days. Residue gas will be redelivered into limited available pipeline interconnects while the Carthage Hub undergoes inspection and repairs.
In February 2009, Midstream entered into an agreement to contribute an additional 25.1% interest in East Texas to Partners in exchange for 3.5 million Class D units. This transaction is expected to close in April 2009. Subsequent to this transaction, Partners will consolidate East Texas in their consolidated financial statements.

~~209~~
~~DCP EAST TEXAS HOLDINGS, LLC~~
~~SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES~~

Charged to

Balance at
Consolidated
Balance at

Beginning of
Statements of
Deductions/
End of

Period Operations Other Period
(Millions)

December 31, 2008

Allowance for doubtful accounts $ 0.5 $ (0.1 ) $ — $ 0.4

December 31, 2007

Allowance for doubtful accounts $ 0.2 $ 0.3 $ — $ 0.5
Environmental 0.3 — (0.3 ) —

$ 0.5 $ 0.3 $ (0.3 ) $ 0.5

December 31, 2006

Allowance for doubtful accounts $ 0.1 $ 0.1 $ — $ 0.2
Environmental 0.4 — (0.1 ) 0.3

$ 0.5 $ 0.1 $ (0.1 ) $ 0.5

~~210~~
~~(c)~~ ~~Exhibits~~
A list of exhibits required by Item 601 ofRegulation S-K to be filed as part of this report:

Exhibit

Number

Description

3 .1 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.
10 .1* Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .2* Bridge Credit Agreement, dated May 9, 2007 among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.2 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .3* Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .4* First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .5* Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .6* Common Unit Purchase Agreement, dated May 21, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .7* Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .8* Common Unit Purchase Agreement, dated June 19, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007).
10 .9* Registration Rights Agreement, dated June 22, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007).
10 .10* Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 27, 2007).
10 .11* Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007).
10 .12* Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007).
10 .13* Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LPForm 10-Q (FileNo. 001-32678) filed with the Securities and Exchange Commission on August 9, 2007).

~~211~~

Exhibit

Number

Description

10 .14* Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007).
10 .15* Registration Rights Agreement, dated August 29, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007).
10 .16 Contribution Agreement dated February 24, 2009, among DCP Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP, LP and DCP Midstream, LLC.
12 .1 Ratio of Earnings to Fixed Charges.
21 .1 List of Subsidiaries of DCP Midstream Partners, LP.
23 .1 Consent of Deloitte & Touche LLP on Consolidated Financial Statements and Financial Statement Schedule of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting.
23 .2 Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC.
23 .3 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP East Texas Holdings, LLC.
23 .4 Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream GP, LP.
23 .5 Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream, 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.
99 .1 Consolidated Balance Sheet of DCP Midstream GP, LP as of December 31, 2008.
99 .2 Consolidated Balance Sheet of DCP Midstream, LLC as of December 31, 2008.
*
Exhibit
Number
Description
2.1* Contribution Agreement, dated October 9, 2006, between DCP LP Holdings, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on October 13, 2006).
2.2* Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
2.3* Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
2.4* Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
2.5* Contribution Agreement dated February 24, 2009, among DCP LP Holdings, LLC, DCP Midstream GP, LP DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 10.16 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
2.6* Purchase and Sale Agreement by and Among DCP Midstream, LLC and DCP Midstream Partners, LP dated as of November 4, 2010 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2010).
2.7* Contribution Agreement between DCP Southeast Texas, LLC and DCP Partners SE Texas LLC dated as of November 4, 2010 (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2010).
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* 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 (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 the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (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).
4.1* Indenture dated as of September 30, 2010 for the issuance of debt securities between DCP Midstream Operating, LP, as issuer, any Guarantors party hereto and The Bank of New York Mellon Trust Company, N.A. (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
Exhibit
Number
Description
4.2* First Supplemental Indenture Dated as of September 30, 2010 to Indenture dated September 30, 2010 for the issuance of 3.25% Senior Notes due 2015 by DCP Midstream Operating, LP as Issuer, DCP Midstream Partners, LP as Guarantor and the Bank of New York Mellon Trust Company, N.A. (attached as Exhibit 4.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
10.1* Omnibus Agreement, dated December 7, 2005, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.4 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.2*+ DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.3*+ Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Form S-8 (File No. 001-32678) filed with the SEC on April 20, 2007).
10.4*+ Form of Performance Phantom Unit Grant Agreement for Officers/Employees under the DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on February 24, 2011).
10.5+ Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream Partners, LP Long-Term Incentive Plan.
10.6* Contribution, Conveyance and Assumption Agreement, dated December 7, 2005, among DCP Midstream Partners, LP, DCP Midstream Operating LP, DCP Midstream GP, LLC, DCP Midstream GP, LP, Duke Energy Field Services, LLC, DEFS Holding 1, LLC, DEFS Holding, LLC, DCP Assets Holdings, LP, DCP Assets Holdings, GP, LLC, Duke Energy Guadalupe Pipeline Holdings, Inc., Duke Energy NGL Services, LP, DCP LP Holdings, LP and DCP Black Lake Holdings, LLC (attached as Exhibit 10.3 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.7* First Amendment to Omnibus Agreement, dated April 1, 2006, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.6 to DCP Midstream Partners, LP’s Form 10-Q (File No. 001-32678) filed with the SEC on August 11, 2006).
10.8* Second Amendment to Omnibus Agreement, dated November 1, 2006, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
10.9* Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC (f/k/a Duke Energy Field Services, LLC), DCP Midstream GP, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
10.10* First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
10.11* Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 10-Q (File No. 001-32678) filed with the SEC on November 9, 2010).
Exhibit
Number
Description
10.12* Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC f/k/a/ Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
10.13* Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
10.14* Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 10-Q (File No. 001-32678) filed with the SEC on August 9, 2007).
10.15* Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on September 5, 2007).
10.16* Second Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated April 1, 2009 between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.17* Tenth Amendment to Omnibus Agreement, dated December 3, 2009, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.25 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 11, 2010).
10.18*++ Amended and Restated General Partnership Agreement of DCP Southeast Texas Holdings, GP, dated as of January 1, 2011, by and among DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP Partners SE Texas LLC, (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2011).
10.19 Twelfth Amendment to Omnibus Agreement, dated January 1, 2011, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP
10.20*++ Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Periodic Report (File No. 001-32678) on Form 10-Q filed August 8, 2008.
10.21*++ Amendment dated June 15, 2010 to Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Periodic Report (File No. 001-32678) on Form 10-Q filed August 9, 2010.
10.22 First Amendment to Amended and Restated General Partnership Agreement of DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP Partners SE Texas, LLC.
12.1 Ratio of Earnings to Fixed Charges.
21.1 List of Subsidiaries of DCP Midstream Partners, LP.
23.1 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting.
Exhibit
Number
Description
23.2 Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services 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.
* Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
~~212~~
+ Denotes management contract or compensatory plan or arrangement.
++ Confidential treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed separately with the SEC.
SIGNATURES
~~SIGNATURES~~
Pursuant to the requirements of the Section 13 or 15(d) 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 March ~~5, 2009.~~
1, 2011.
~~DCP Midstream Partners, LP~~
DCP Midstream Partners, LP
By: ~~/s/~~   DCP Midstream GP, LP
~~its General Partner~~
its General Partner
By: ~~By:~~ ~~/s/~~  DCP Midstream GP, LLC
~~its General Partner~~
its General Partner
By: ~~By:~~ /s/    Mark A. Borer
~~Name:     Mark A. Borer~~
Name:  Mark A. Borer
Title:
President and Chief Executive Officer

~~213~~
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears below constitutes and appoints each of Mark A. Borer and Angela A. Minas ashis/her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or in his name, place, and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this annual report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature

Title

Date
~~Signature~~ ~~Title~~ ~~Date~~
/s/    Mark A. Borer

Mark A. Borer
President, Chief Executive Officer and Director (Principal Executive Officer)    March ~~5, 2009~~1, 2011
/s/    Angela A. Minas

Angela A. Minas
Vice President and Chief Financial Officer (Principal Financial Officer)    March ~~5, 2009~~1, 2011
/s/    Scott R. Delmoro

Scott R. Delmoro
Chief Accounting Officer (Principal Accounting Officer)    March ~~5, 2009~~1, 2011
/s/    Thomas C. O’Connor

Thomas C. O’Connor
Chairman of the Board and Director    March ~~5, 2009~~1, 2011
/s/    Paul F. Ferguson, Jr.

Paul F. Ferguson, Jr.
Director    March ~~5, 2009~~1, 2011
/s/    ~~Gregory J. Goff~~

~~Gregory J. Goff~~Alan N. Harris
Alan N. Harris
Director    March ~~5, 2009~~1, 2011
/s/    ~~Alan N. Harris~~

~~Alan N. Harris~~Donald G. Hrap
Donald G. Hrap
Director    March ~~5, 2009~~1, 2011
/s/    John E. Lowe

John E. Lowe
Director    March ~~5, 2009~~1, 2011
/s/    Frank A. McPherson

Frank A. McPherson
Director    March ~~5, 2009~~1, 2011
/s/    Thomas C. Morris

Thomas C. Morris
Director    March ~~5, 2009~~1, 2011
/s/    Stephen R. Springer

Stephen R. Springer
Director    March ~~5, 2009~~1, 2011

~~214~~

EXHIBIT INDEX

Exhibit

Number

Description

3 .1 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.
10 .1* Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .2* Bridge Credit Agreement, dated May 9, 2007 among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.2 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .3* Contribution and Sale Agreement, dated May 9, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .4* First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007).
10 .5* Contribution Agreement, dated May 21, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .6* Common Unit Purchase Agreement, dated May 21, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .7* Contribution Agreement, dated May 23, 2007, among DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007).
10 .8* Common Unit Purchase Agreement, dated June 19, 2007, among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007).
10 .9* Registration Rights Agreement, dated June 22, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007).
10 .10* Amended and Restated Credit Agreement, dated July 1, 2007, among DCP Midstream, LLC and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 27, 2007).
10 .11* Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007).
10 .12* Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007).
10 .13* Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LPForm 10-Q (FileNo. 001-32678) filed with the Securities and Exchange Commission on August 9, 2007).

~~215~~

Exhibit

Number

Description

10 .14* Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007).
10 .15* Registration Rights Agreement, dated August 29, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007).
10 .16 Contribution Agreement dated February 24, 2009, among DCP Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP, LP and DCP Midstream, LLC.
12 .1 Ratio of Earnings to Fixed Charges.
21 .1 List of Subsidiaries of DCP Midstream Partners, LP.
23 .1 Consent of Deloitte & Touche LLP on Consolidated Financial Statements and Financial Statement Schedule of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting.
23 .2 Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC.
23 .3 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP East Texas Holdings, LLC.
23 .4 Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream GP, LP.
23 .5 Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream, 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.
99 .1 Consolidated Balance Sheet of DCP Midstream GP, LP as of December 31, 2008.
99 .2 Consolidated Balance Sheet of DCP Midstream, LLC as of December 31, 2008.
*
Exhibit
Number
Description
2.1* Contribution Agreement, dated October 9, 2006, between DCP LP Holdings, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on October 13, 2006).
2.2* Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
2.3* Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
2.4* Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
2.5* Contribution Agreement dated February 24, 2009, among DCP LP Holdings, LLC, DCP Midstream GP, LP DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 10.16 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
2.6* Purchase and Sale Agreement by and Among DCP Midstream, LLC and DCP Midstream Partners, LP dated as of November 4, 2010 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2010).
2.7* Contribution Agreement between DCP Southeast Texas, LLC and DCP Partners SE Texas LLC dated as of November 4, 2010 (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2010).
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* 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 (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 the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (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).
4.1* Indenture dated as of September 30, 2010 for the issuance of debt securities between DCP Midstream Operating, LP, as issuer, any Guarantors party hereto and The Bank of New York Mellon Trust Company, N.A. (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
4.2* First Supplemental Indenture Dated as of September 30, 2010 to Indenture dated September 30, 2010 for the issuance of 3.25% Senior Notes due 2015 by DCP Midstream Operating, LP as Issuer, DCP Midstream Partners, LP as Guarantor and the Bank of New York Mellon Trust Company, N.A. (attached as Exhibit 4.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
10.1* Omnibus Agreement, dated December 7, 2005, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.4 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.2*+ DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.3*+ Form of Phantom Unit Grant Agreement for Directors under the DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Form S-8 (File No. 001-32678) filed with the SEC on April 20, 2007).
10.4*+ Form of Performance Phantom Unit Grant Agreement for Officers/Employees under the DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on February 24, 2011).
10.5+ Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream Partners, LP Long-Term Incentive Plan.
10.6* Contribution, Conveyance and Assumption Agreement, dated December 7, 2005, among DCP Midstream Partners, LP, DCP Midstream Operating LP, DCP Midstream GP, LLC, DCP Midstream GP, LP, Duke Energy Field Services, LLC, DEFS Holding 1, LLC, DEFS Holding, LLC, DCP Assets Holdings, LP, DCP Assets Holdings, GP, LLC, Duke Energy Guadalupe Pipeline Holdings, Inc., Duke Energy NGL Services, LP, DCP LP Holdings, LP and DCP Black Lake Holdings, LLC (attached as Exhibit 10.3 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
10.7* First Amendment to Omnibus Agreement, dated April 1, 2006, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.6 to DCP Midstream Partners, LP’s Form 10-Q (File No. 001-32678) filed with the SEC on August 11, 2006).
10.8* Second Amendment to Omnibus Agreement, dated November 1, 2006, among Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
10.9* Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC (f/k/a Duke Energy Field Services, LLC), DCP Midstream GP, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
10.10* First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
10.11* Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 10-Q (File No. 001-32678) filed with the SEC on November 9, 2010).
10.12* Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC f/k/a/ Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
10.13* Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
10.14* Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Form 10-Q (File No. 001-32678) filed with the SEC on August 9, 2007).
10.15* Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on September 5, 2007).
10.16* Second Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated April 1, 2009 between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.17* Tenth Amendment to Omnibus Agreement, dated December 3, 2009, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.25 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 11, 2010).
10.18*++ Amended and Restated General Partnership Agreement of DCP Southeast Texas Holdings, GP, dated as of January 1, 2011, by and among DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP Partners SE Texas LLC, (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s current report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2011).
10.19 Twelfth Amendment to Omnibus Agreement, dated January 1, 2011, among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP
10.20*++ Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Periodic Report (File No. 001-32678) on Form 10-Q filed August 8, 2008.
10.21*++ Amendment dated June 15, 2010 to Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Periodic Report (File No. 001-32678) on Form 10-Q filed August 9, 2010.
10.22 First Amendment to Amended and Restated General Partnership Agreement of DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP Partners SE Texas, LLC.
12.1 Ratio of Earnings to Fixed Charges.
21.1 List of Subsidiaries of DCP Midstream Partners, LP.
23.1 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting.
23.2 Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services 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.
* Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
~~216~~
+ Denotes management contract or compensatory plan or arrangement.
++ Confidential treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed separately with the SEC.
213

	¨	~~For the fiscal year ended: December 31, 2008~~
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		~~For the transition period from to~~


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

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


Title of Each Class:		Name of Each Exchange on Which Registered:

Common Units Representing Limited Partner Interests		New York Stock Exchange


Large accelerated filer ox		Accelerated filer þ¨		Non-accelerated filer o¨		Smaller reporting company o¨



Bbl		barrel

Bbls/d		barrels per day

BBtu/d		one billion Btus per day

Bcf		one billion cubic feet

Bcf/d		one billion cubic feet per day

Btu		British thermal unit, a measurement of energy

Fractionation		the process by which natural gas liquids are separated into individual components

Frac spread		price differences, measured in energy units, between equivalent amounts of natural gas and NGLs

MBbls		one thousand barrels

MMBbls		one million barrels

MBbls/d		one thousand barrels per day

MMBtu		one million Btus

MMBtu/d		one million Btus per day

MMcf		one million cubic feet

MMcf/d		one million cubic feet per day

MMscf		one million standard cubic feet

NGLs		natural gas liquids

Tcf		one trillion cubic feet

Throughput		the volume of product transported or passing through a pipeline or other facility

	x
~~(Mark One)~~

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


Item			Page

PART I.
	1.	Business		2
	1A.	Risk Factors		27
	1B.	Unresolved Staff Comments		49
	2.	Properties		49
	3.	Legal Proceedings		50
	4.	Submission of Matters to a Vote of Unitholders		50

PART II.
	5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Units		51
	6.	Selected Financial Data		54
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		55
	7A.	Quantitative and Qualitative Disclosures about Market Risk		94
	8.	Financial Statements and Supplementary Data		100
	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		151
	9A.	Controls and Procedures		151
	9B.	Other Information		154

PART III.
	10.	Directors, Executive Officers and Corporate Governance		154
	11.	Executive Compensation		160
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		172
	13.	Certain Relationships and Related Transactions, and Director Independence		173
	14.	Principal Accounting Fees and Services		178

PART IV.
	15.	Exhibits and Financial Statement Schedules		179
Signatures				213
Exhibit Index				215
EX-3.1
EX-10.16
EX-12.1
EX-21.1
EX-23.1
EX-23.2
EX-23.3
EX-23.4
EX-23.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1
EX-99.2


Item		Page

	PART I.

1.	Business		3

1A.	Risk Factors		27

1B.	Unresolved Staff Comments		51

2.	Properties		51

3.	Legal Proceedings		51

4.	Reserved		52

	PART II.

5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Units		53

6.	Selected Financial Data		54

7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		57

7A.	Quantitative and Qualitative Disclosures about Market Risk		91

8.	Financial Statements and Supplementary Data		98

9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		162

9A.	Controls and Procedures		162

9B.	Other Information		164

	PART III.

10.	Directors, Executive Officers and Corporate Governance		164

11.	Executive Compensation		170

12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		184

13.	Certain Relationships and Related Transactions, and Director Independence		185

14.	Principal Accounting Fees and Services		190

	PART IV.

15.	Exhibits and Financial Statement Schedules		191

Signatures			208

Exhibit Index			210


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

	•	~~general economic, market and business conditions;~~

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

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

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

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

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

	•	~~the creditworthiness of counterparties to our transactions;~~

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

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

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

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


	•	Our Northern Louisiana system, which is an integrated pipeline system located in northern Louisiana and southern Arkansas that gathers, compresses, treats, processes, transports and sells natural gas, and that transports and sells NGLs and condensate. This system consists of the following:


	•	~~the Minden processing plant and gathering system, which includes a115 MMcf/d~~ cryogenic natural gas processing plant supplied by approximately 725 miles of natural gas gathering pipelines, connected to approximately 460 receipt points, with throughput and processing capacity of approximately~~115 MMcf/d;~~

	•	~~the Ada processing plant and gathering system, which includes a45 MMcf/d~~ refrigeration natural gas processing plant supplied by approximately 130 miles of natural gas gathering pipelines, connected to approximately 210 receipt points, with throughput capacity of approximately~~80 MMcf/d; and~~


	•	~~the Pelico Pipeline, LLC system, or Pelico system, an approximately600-mile~~ ~~intrastate natural gas gathering and transportation pipeline with throughput capacity of approximately250 MMcf/d~~ and connections to the Minden and Ada processing plants and approximately 450 other receipt points. The Pelico system delivers natural gas to multiple interstate and intrastate pipelines, as well as directly to industrial and utility end-use markets.


	•	~~Our Southern Oklahoma, or Lindsay, gathering system, which was acquired in May 2007, consists of approximately 225 miles of pipeline, with throughput capacity of approximately35 MMcf/d.~~

	•	~~Our equity interests that were acquired in July 2007 from DCP Midstream, LLC, consist of the following:~~


	•	~~our 40% interest in Discovery Producer Services LLC, or Discovery, which operates a600 MMcf/d~~ ~~cryogenic natural gas processing plant, a natural gas liquids fractionator plant, an approximately280-mile~~ ~~natural gas pipeline with approximate throughput capacity of600 MMcf/d~~ ~~that transports gas from the Gulf of Mexico to its processing plant, and several onshore laterals expanding its presence in the Gulf; and~~

	•	~~our 25% interest in DCP East Texas Holdings, LLC, or East Texas, which operates a780 MMcf/d~~ ~~natural gas processing complex, a natural gas liquids fractionator and an approximately900-mile~~ ~~gathering system with approximate throughput capacity of780 MMcf/d,~~ ~~as well as third party gathering systems, and delivers residue gas to interstate and intrastate pipelines.~~


	•	~~Our Colorado and Wyoming gathering, processing and compression assets were acquired in August 2007 from DCP Midstream, LLC, and consist of the following:~~


Item 1A.	*Risk Factors*


	•	~~our 70% operating interest in the approximately30-mile~~ Collbran Valley Gas Gathering system, or Collbran system, has assets in the Piceance Basin that gather and process natural gas from over 20,000 dedicated acres in western Colorado, and a processing facility with a capacity of~~120 MMcf/d; and~~

	•	~~The Powder River Basin assets, which include the approximately 1,320-mile Douglas gas gathering system, or Douglas system, with throughput capacity of approximately60 MMcf/d~~ ~~and covers~~website and the information contained on that site, or connected to that site, are not incorporated by reference into this report. For more ~~than 4,000 square miles in northeastern Wyoming, and Millis terminal, and associated NGL pipelines in southwestern Wyoming.~~


	•	Our Michigan gathering and treating assets were acquired in October 2008 from Michigan Pipeline & Processing, LLC, or MPP. These assets consist of five natural gas treating plants and an approximately~~155-mile~~ ~~gas gathering pipeline system with throughput capacity of330 MMcf/d;~~ ~~an approximately55-mile~~ ~~residue gas pipeline; a 75% interest in Jackson Pipeline Company, a partnership owning an approximately25-mile~~ ~~residue pipeline, or Jackson Pipeline; and a 44% interest in the Litchfield pipeline, a30-mile~~ ~~pipeline whereby we lease our undivided interest to ANR Pipeline Company through the use of a direct financing lease expiring in 2031.~~


	•	~~six owned rail terminals located in the Midwest and northeastern United States, one of which was idled in 2007 to consolidate our operations, with aggregate storage capacity of 25 MBbls;~~

	•	~~one leased marine terminal located in Providence, Rhode Island, with storage capacity of 410 MBbls;~~

	•	~~one pipeline terminal located in Midland, Pennsylvania with storage capacity of 56 MBbls; and~~

	•	~~access to several open access pipeline terminals.~~


	•	~~our Seabreeze pipeline, an approximately68-mile~~ ~~intrastate NGL pipeline located in Texas with throughput capacity of 33 MBbls/d;~~


	•	~~our Wilbreeze pipeline, the construction of which was completed in December 2006, an approximately39-mile~~ ~~intrastate NGL pipeline located in Texas, which connects a DCP Midstream, LLC gas processing plant to the Seabreeze pipeline, with throughput capacity of 11 MBbls/d; and~~

	•	~~our 45% interest in the Black Lake Pipe Line Company, or Black Lake, the owner of an approximately317-mile~~ ~~interstate NGL pipeline in Louisiana and Texas with throughput capacity of 40 MBbls/d.~~


	Approximate
	Gas Gathering								Approximate			2008 Operating Data
	and		Partnership		Plants		Fractionator		Net Plant			Natural Gas			NGL
	Transmission		Operated		Operated		Operated by		Capacity			Throughput			Production
System	System (Miles)		Plants		by Others		Others		(MMcf/d)			(MMcf/d)(a)			(Bbls/d)(a)

Minden		725		1		—		—		115			83			4,619
Ada		130		1		—		—		45			62			165
Pelico		600		—		—		—		—			171			—
Southern Oklahoma (Lindsay)		225		—		—		—		—			18			2,203
Collbran		30		1		—		—		120			90			486
Douglas		1,320		—		—		—		—			16			1,025
Michigan		265		—		—		—		—			75			—
Discovery		280		—		1		1		240	(b)		170	(b)		4,703	(b)
East Texas		900		—		1		1		195	(b)		153	(b)		7,458	(b)

Total		4,475		3		2		2		715			838			20,659


System	Approximate Gas Gathering and Transmission Systems (Miles)		Plants			Fractionators			Approximate Net Plant Capacity (MMcf/d)(a)		Approximate Natural Gas Storage Capacity(Bcf)			2010 Operating data
System	Approximate Gas Gathering and Transmission Systems (Miles)		Plants			Fractionators			Approximate Net Plant Capacity (MMcf/d)(a)		Approximate Natural Gas Storage Capacity(Bcf)			Natural Gas Throughput (MMcf/d)(a)			NGL Production (Bbls/d)(a)
Minden		725		1	(c)		—			115		—			62			4,081
Ada		130		1	(c)		—			45		—			41			184
Pelico		600		—			—			—		—			146			—
Southern Oklahoma		225		—			—			—		—			17			1,995
Colorado		40		1	(d)		—			84		—			63			2,961
Wyoming		1,300		—			—			—		—			21			2,002
Michigan		440		4	(d)		—			455		—			358			—
Discovery		300		1	(c)(e)		1	(e)		240		—			200			9,018
East Texas		900		1	(c)		1			391		—			260			13,280
Southeast Texas		675		3	(c)		—			127		3	(b)		(f	)		(f	)

Total		5,335		12			2			1,457		3			1,168			33,521


(a)		Represents total capacity or total volumes allocated to our proportionate ownership share for ~~2008~~2010 divided by ~~366~~365 days.


	•	~~certification and construction of new facilities;~~

	•	~~extension or abandonment of services and facilities;~~

	•	~~maintenance of accounts and records;~~

	•	~~acquisition and disposition of facilities;~~

	•	~~initiation and discontinuation of services;~~

	•	~~terms and conditions of services and service contracts with customers;~~

	•	~~depreciation and amortization policies;~~

	•	~~conduct and relationship with certain affiliates; and~~

	•	~~various other matters.~~


	•	~~requiring the acquisition of permits to conduct regulated activities;~~

	•	~~restricting the way we can handle or dispose of our wastes;~~

	•	~~limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;~~

	•	~~requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and~~

	•	~~enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.~~


	•	~~the fees we charge and the margins we realize for our services;~~

	•	~~the prices of, level of production of, and demand for, natural gas, propane, condensate and NGLs;~~

	•	~~the success of our commodity derivative and interest rate hedging programs in mitigating fluctuations in commodity prices and interest rates;~~

	•	~~the volume of natural gas we gather, treat, compress, process, transport and sell, the volume of propane and NGLs we transport and sell, and the volumes of propane we store;~~

	•	~~the relationship between natural gas, NGL and crude oil prices;~~

	•	~~the level of competition from other energy companies;~~

	•	~~the impact of weather conditions on the demand for natural gas and propane;~~

	•	~~the level of our operating and maintenance and general and administrative costs; and~~

	•	~~prevailing economic conditions.~~


	•	~~the level of capital expenditures we make;~~

	•	~~the cost and form of payment for acquisitions;~~

	•	~~our debt service requirements and other liabilities;~~

	•	~~fluctuations in our working capital needs;~~

	•	~~our ability to borrow funds and access capital markets at reasonable rates;~~

	•	~~restrictions contained in our debt agreements;~~

	•	~~the amount of cash distributions we receive from our equity interests; and~~

	•	~~the amount of cash reserves established by our general partner.~~


	•	We have limited ability to influence decisions with respect to the operations of these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us;

	•	~~These entities may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would otherwise reduce cash available for distribution to us;~~

	•	~~These entities may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us; and~~

	•	These entities may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.


	•	the impact of weather, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, or extreme weather that may disrupt our operations or related downstream operations;

	•	~~the level of domestic and offshore production;~~

	•	~~a general downturn in economic conditions, including demand for NGLs;~~

	•	~~the availability of imported natural gas, NGLs and crude oil and the demand in the U.S. and globally for these commodities;~~

	•	~~actions taken by foreign oil and gas producing nations;~~

	•	~~the availability of local, intrastate and interstate transportation systems;~~

	•	~~the availability and marketing of competitive fuels;~~

	•	~~the extent of governmental regulation and taxation.~~


	•	~~identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other midstream assets for acquisitions, joint ventures and construction projects;~~

	•	~~consummate accretive acquisitions or joint ventures and complete construction projects;~~

	•	~~appropriately identify liabilities associated with acquired businesses or assets;~~

	•	~~integrate acquired or constructed businesses or assets successfully with our existing operations and into our operating and financial systems and controls;~~

	•	~~hire, train and retain qualified personnel to manage and operate our growing business; and~~

	•	~~obtain required financing for our existing and new operations.~~


	•	~~perform ongoing assessments of pipeline integrity;~~

	•	~~identify and characterize applicable threats to pipeline segments that could impact a high consequence area;~~

	•	~~improve data collection, integration and analysis;~~

	•	~~repair and remediate the pipeline as necessary; and~~

	•	~~implement preventive and mitigating actions.~~


	•	mistaken assumptions about volumes, future contract terms with customers, revenues and costs, including synergies;

	•	~~an inability to successfully integrate the businesses we acquire;~~

	•	~~the assumption of unknown liabilities;~~


	•	~~limitations on rights to indemnity from the seller;~~

	•	~~mistaken assumptions about the overall costs of equity or debt;~~

	•	~~the diversion of management’s and employees’ attention from other business concerns;~~

	•	~~change in competitive landscape;~~

	•	~~unforeseen difficulties operating in new product areas or new geographic areas; and~~

	•	~~customer or key employee losses at the acquired businesses.~~


	•	~~damage to pipelines, plants and terminals, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;~~

	•	~~inadvertent damage from construction, farm and utility equipment;~~

	•	~~leaks of natural gas, propane, NGLs and other hydrocarbons or losses of natural gas, propane or NGLs as a result of the malfunction of equipment or facilities;~~

	•	~~contaminants in the pipeline system;~~

	•	~~fires and explosions; and~~

	•	~~other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.~~


	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•	~~an increased amount of cash flow will be required to make interest payments on our debt;~~

	•	~~our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and~~

	•	~~our debt level may limit our flexibility in responding to changing business and economic conditions.~~