Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

DCP Midstream GP, LLC

Denver, Colorado

We have audited the accompanying consolidated balance sheets of DCP Midstream Partners, LP and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. 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 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 $139,509,000 and $139,233,000 at December 31, 2011 and 2010, respectively, and in Discovery’s net income of $20,323,000, $20,570,000, and $14,204,000 for the years ended December 31, 2011, 2010, and 2009, 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, such consolidated statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements give retrospective effect to the 100% ownership interest in DCP Southeast Texas Holdings, GP, of which 33.33% and 66.67% was acquired on January 1, 2011 and March 30, 2012, respectively, from DCP Midstream, LLC, as a combination of entities under common control, which has been accounted for in a manner similar to a pooling of interests, as described in Note 1 to the consolidated financial statements.

Also as described in Note 1 to the consolidated financial statements, the portion of the accompanying consolidated financial statements for the three years in the period ended December 31, 2011 attributable to DCP Southeast Texas Holdings, GP 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 DCP Southeast Texas Holdings, GP 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.

The consolidated financial statements give retrospective effect to the changes to the preliminary purchase price allocation for Marysville Hydrocarbon Holdings, Inc. as described in Note 1 to the consolidated financial 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, 2011, based on the criteria established in the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 29, 2012

(June 14, 2012 as to Notes 1, 4 and 23)

1

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	7.6		$	6.7
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.3 million and $0.5 million, respectively		108.6			140.4
Affiliates		106.2			106.9
Inventories		87.9			73.6
Unrealized gains on derivative instruments		41.2			14.5
Assets held for sale		—			6.2
Other		2.2			2.1
Total current assets		353.7			350.4
Property, plant and equipment, net		1,499.4			1,378.6
Goodwill		153.8			151.2
Intangible assets, net		145.3			153.0
Investments in unconsolidated affiliates		107.1			104.3
Unrealized gains on derivative instruments		6.4			1.9
Other long-term assets		11.7			7.8
Total assets	$	2,277.4		$	2,147.2
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	231.7		$	173.4
Affiliates		46.8			37.6
Unrealized losses on derivative instruments		59.9			56.6
Other		42.1			47.7
Total current liabilities		380.5			315.3
Long-term debt		746.8			647.8
Unrealized losses on derivative instruments		32.8			50.5
Other long-term liabilities		19.0			57.6
Total liabilities		1,179.1			1,071.2
Commitments and contingent liabilities:
Equity:
Predecessor equity		257.4			337.8
Common unitholders (44,848,703 and 40,478,383 units issued and outstanding, respectively)		654.4			552.2
General partner		(4.7	)		(6.4	)
Accumulated other comprehensive loss		(21.2	)		(27.7	)
Total partners’ equity		885.9			855.9
Noncontrolling interests		212.4			220.1
Total equity		1,098.3			1,076.0
Total liabilities and equity	$	2,277.4		$	2,147.2

See accompanying notes to consolidated financial statements.

2

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2011			2010			2009
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	1,067.6		$	1,050.9		$	730.7
Sales of natural gas, propane, NGLs and condensate to affiliates		1,110.9			924.2			698.6
Transportation, processing and other		138.8			108.1			88.9
Transportation, processing and other to affiliates		33.4			22.2			16.0
Gains (losses) from commodity derivative activity, net		6.8			5.3			(53.4	)
Gains (losses) from commodity derivative activity, net — affiliates		0.9			(2.3	)		(2.9	)
Total operating revenues		2,358.4			2,108.4			1,477.9
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,485.8			1,504.9			1,001.0
Purchases of natural gas, propane and NGLs from affiliates		447.2			278.2			247.3
Operating and maintenance expense		125.7			98.3			84.2
Depreciation and amortization expense		100.6			88.1			76.9
General and administrative expense		18.9			14.3			11.9
General and administrative expense — affiliates		29.4			31.5			31.2
Step acquisition — equity interest re-measurement gain		—			(9.1	)		—
Other (income) expense		(0.5	)		(2.0	)		0.5
Other income — affiliates		—			(3.0	)		—
Total operating costs and expenses		2,207.1			2,001.2			1,453.0
Operating income		151.3			107.2			24.9
Interest income		—			—			0.3
Interest expense		(33.9	)		(29.1	)		(28.3	)
Earnings from unconsolidated affiliates		22.7			23.8			18.5
Income before income taxes		140.1			101.9			15.4
Income tax expense		(0.5	)		(1.5	)		(1.0	)
Net income		139.6			100.4			14.4
Net income attributable to noncontrolling interests		(18.8	)		(9.2	)		(8.3	)
Net income attributable to partners		120.8			91.2			6.1
Net income attributable to predecessor operations		(20.4	)		(43.2	)		(24.2	)
General partner’s interest in net income		(25.2	)		(16.9	)		(12.7	)
Net income (loss) allocable to limited partners	$	75.2		$	31.1		$	(30.8	)
Net income (loss) per limited partner unit — basic	$	1.73		$	0.86		$	(0.99	)
Net income (loss) per limited partner unit — diluted	$	1.72		$	0.86		$	(0.99	)
Weighted-average limited partner units outstanding — basic		43.5			36.1			31.2
Weighted-average limited partner units outstanding — diluted		43.6			36.1			31.2

See accompanying notes to consolidated financial statements.

3

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2011			2010			2009
	(Millions)
Net income	$	139.6		$	100.4		$	14.4
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings		20.7			22.9			20.6
Net unrealized losses on cash flow hedges		(13.3	)		(18.7	)		(12.0	)
Net unrealized losses on cash flow hedges - predecessor		(1.8	)		—			(2.0	)
Total other comprehensive income		5.6			4.2			6.6
Total comprehensive income		145.2			104.6			21.0
Total comprehensive income attributable to noncontrolling interests		(18.8	)		(9.2	)		(8.3	)
Total comprehensive income attributable to partners	$	126.4		$	95.4		$	12.7

See accompanying notes to consolidated financial statements.

4

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Partner’s Equity
	Predecessor Equity			Common Unitholders			General Partner			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2011	$	337.8		$	552.2		$	(6.4	)	$	(27.7	)	$	220.1		$	1,076.0
Net change in parent advances		15.3			—			—			—			—			15.3
Acquisition of Southeast Texas		(114.3	)		—			—			—			—			(114.3	)
Excess purchase price over acquired assets		—			(34.8	)		—			(0.9	)		—			(35.7	)
Issuance of 4,357,921 common units		—			169.9			—			—			—			169.9
Equity-based compensation		—			3.4			—			—			—			3.4
Distributions to DCP Midstream, LLC		—			(2.6	)		—			—			—			(2.6	)
Distributions to unitholders and general partner		—			(108.9	)		(23.5	)		—			—			(132.4	)
Distributions to noncontrolling interests		—			—			—			—			(44.8	)		(44.8	)
Contributions from noncontrolling interests		—			—			—			—			18.3			18.3
Comprehensive income:
Net income attributable to predecessor operations		20.4			—			—			—			—			20.4
Net income		—			75.2			25.2			—			18.8			119.2
Reclassification of cash flow hedges into earnings		—			—			—			20.7			—			20.7
Net unrealized losses on cash flow hedges		(1.8	)		—			—			(13.3	)		—			(15.1	)
Total comprehensive income		18.6			75.2			25.2			7.4			18.8			145.2
Balance, December 31, 2011	$	257.4		$	654.4		$	(4.7	)	$	(21.2	)	$	212.4		$	1,098.3

See accompanying notes to consolidated financial statements.

5

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY — (Continued)

	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, 2009	$	283.6		$	429.0		$	—		$	(54.6	)	$	(4.8	)	$	(40.5	)	$	167.7		$	780.4
Net change in parent advances		(25.5	)		—			—			—			—			—			—			(25.5	)
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 income attributable to predecessor operations		24.2			—			—			—			—			—			—			24.2
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		(2.0	)		—			—			—			—			(12.0	)		—			(14.0	)
Total comprehensive income (loss)		22.2			(30.6	)		(4.4	)		4.6			12.3			8.6			8.3			21.0
Balance, December 31, 2009	$	212.3		$	415.5		$	—		$	—		$	(5.9	)	$	(31.9	)	$	227.7		$	817.7
Net change in parent advances		82.3			—			—			—			—			—			—			82.3
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 attributable to predecessor operations		43.2			—			—			—			—			—			—			43.2
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		43.2			32.2			—			—			15.8			4.2			9.2			104.6
Balance, December 31, 2010	$	337.8		$	552.2		$	—		$	—		$	(6.4	)	$	(27.7	)	$	220.1		$	1,076.0

See accompanying notes to consolidated financial statements.

6

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	139.6		$	100.4		$	14.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		100.6			88.1			76.9
Earnings from unconsolidated affiliates		(22.7	)		(23.8	)		(18.5	)
Distributions from unconsolidated affiliates		25.3			30.0			20.2
Step acquisition – equity interest re-measurement gain		—			(9.1	)		—
Net unrealized (gains) losses on derivative instruments		(39.9	)		8.4			83.8
Deferred income taxes		(29.2	)		(0.1	)		0.1
Other, net		4.2			(0.8	)		0.1
Change in operating assets and liabilities which (used) provided cash, net of effects of acquisitions:
Accounts receivable		31.5			(48.2	)		(34.5	)
Inventories		(14.3	)		1.3			(27.1	)
Accounts payable		63.5			9.9			41.3
Accrued interest		—			1.8			(0.6	)
Other current assets and liabilities		5.6			3.0			(3.9	)
Other long-term assets and liabilities		(3.4	)		1.5			0.5
Net cash provided by operating activities		260.8			162.4			152.7
INVESTING ACTIVITIES:
Capital expenditures		(165.7	)		(75.9	)		(182.2	)
Acquisitions, net of cash acquired		(60.5	)		(282.1	)		(44.5	)
Acquisition of unconsolidated affiliates		(114.3	)		—			—
Investments in unconsolidated affiliates		(7.0	)		(2.3	)		(7.0	)
Return of investment from unconsolidated affiliates		1.6			1.2			2.2
Proceeds from sales of assets		5.2			3.5			1.4
Purchases of available-for-sale securities		—			—			(1.1	)
Proceeds from sales of available-for-sale securities		—			10.1			51.1
Net cash used in investing activities		(340.7	)		(345.5	)		(180.1	)
FINANCING ACTIVITIES:
Proceeds from debt		1,524.0			868.2			237.0
Payments of debt		(1,425.0	)		(833.4	)		(280.5	)
Payment of deferred financing costs		(4.2	)		(2.1	)		—
Proceeds from issuance of common units, net of offering costs		169.7			189.3			69.5
Excess purchase price over acquired assets		(35.7	)		—			—
Net change in advances to predecessor from DCP Midstream, LLC		10.9			82.3			(25.5	)
Distributions to unitholders and general partner		(132.4	)		(101.9	)		(85.3	)
Distributions to noncontrolling interests		(44.8	)		(25.6	)		(27.0	)
Contributions from noncontrolling interests		18.3			13.8			78.7
Contributions from DCP Midstream, LLC		—			0.6			0.7
Purchase of additional interest in a subsidiary		—			(3.5	)		—
Net cash provided by (used in) financing activities		80.8			187.7			(32.4	)
Net change in cash and cash equivalents		0.9			4.6			(59.8	)
Cash and cash equivalents, beginning of period		6.7			2.1			61.9
Cash and cash equivalents, end of period	$	7.6		$	6.7		$	2.1

See accompanying notes to consolidated financial statements.

7

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009

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; and producing, fractionating, transporting, storing and selling NGLs and condensate.

We are a Delaware limited partnership that was formed in August 2005. We completed our initial public offering on December 7, 2005. Our partnership includes: our natural gas services business (which includes our Northern Louisiana system; our Southern Oklahoma system; our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system; a 75% interest in Collbran Valley Gas Gathering, LLC, or Collbran or our Colorado system (of which 5% was acquired in February 2010); our 50.1% interest in DCP East Texas Holdings, LLC, or our East Texas system (of which 25.1% was acquired in April 2009); our Michigan system (a portion of which was acquired November 2009); DCP Southeast Texas Holdings, GP, or our Southeast Texas system (of which 33.33% and 66.67% was acquired in January 2011 and March 2012, respectively); our NGL logistics business (which includes Marysville Hydrocarbons Holdings, LLC, 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: (1) a 5% interest acquired from DCP Midstream, LLC, in a transaction among entities under common control, and (2) an additional 50% interest acquired from an affiliate of BP PLC; and the DJ Basin NGL Fractionators acquired in March 2011); and our wholesale propane logistics business (which includes Atlantic Energy acquired in July 2010).

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to us and operate most of our assets. DCP Midstream, LLC owns approximately 27% of us. Transactions between us and other DCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates.

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. All intercompany balances and transactions have been eliminated.

Our predecessor operations consist of our 25.1% limited liability company interest in East Texas, which we acquired from DCP Midstream, LLC in April 2009, our initial 33.33% interest in Southeast Texas, which we acquired from DCP Midstream, LLC in January 2011, and the remaining 66.67% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business, which we acquired from DCP Midstream, LLC in March 2012. Prior to our acquisition of the remaining 66.67% interest in Southeast Texas, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to this transaction, we own 100% of Southeast Texas which we account for as a consolidated subsidiary. These transfers of net assets between entities under common control were accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of our 25.1% interest in East Texas, 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in excess or deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction of or an addition to partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates and we have retrospectively adjusted the December 31, 2010 consolidated balance sheet for changes in our purchase price allocation for our December 30, 2010 acquisition of Marysville.

8

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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 Investments — We may invest available cash balances in various financial instruments, such as commercial paper and money market 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.

We classify all short-term 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. Short-term 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; interest rates are re-set on a daily, weekly or monthly basis.

Inventories — Inventories, which consist primarily of 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.

Goodwill and Intangible Assets — Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill in the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimate of operating and 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. For certain reporting units, we may elect to first assess qualitative factors to determine whether it is more likely than not that the fair value of our reporting units is less than the carrying value.

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;

• 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

9

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (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 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.

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.

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.

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 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 there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our 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.

Noncontrolling Interest — Noncontrolling interest represents any third party or affiliate interest in non-wholly-owned entities that we 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 noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors.

10

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Accounting for Risk Management Activities and Financial Instruments — Non-trading energy commodity derivatives 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. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchases or normal sale exception is not elected, are recorded at fair value in the consolidated 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	Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity	Mark-to-market method (a)	Net basis in gains and losses from commodity derivative activity
Cash Flow Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item
Fair Value Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item
Normal Purchases or Normal Sales	Accrual method (c)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

(a) 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.

(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 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.

(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.

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 in accumulated other comprehensive income, or 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 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.

11

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Revenue Recognition — We generate the majority of our revenues from gathering, processing, compressing, treating, 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.

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 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/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 condensate 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, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and 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 gas and/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 relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.

• 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.

• 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.

• Collectability is reasonably assured — Collectability is evaluated on a customer-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 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.

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. We recognize revenues for non-trading

12

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity derivative activity. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial or physical energy trading contracts.

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or 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.

Significant Customers — There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2011, 2010 and 2009. There was one third party customer that accounted for approximately 17% of total operating revenues of the Wholesale Propane Logistics segment for the years ended December 31, 2011 and 2010, respectively, and approximately 12% of revenues for the year ended December 31, 2009. We also had significant transactions with 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 assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2011 and 2010, included in the consolidated balance sheets as other current liabilities amounted to $0.8 million and $0.6 million, respectively, and as other long-term liabilities amounted to $1.2 million and $1.3 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.

Net Income or Loss per Limited Partner Unit — Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing limited partners’ interest in net income or loss, by the weighted-average number of outstanding LPUs during the period. Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method.

13

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

3. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2011-11 “Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities,” or ASU 2011-11 — In December 2011, the FASB issued ASU 2011-11, which amends Accounting Standards Codification, or ASC, Topic 210 “Balance Sheet.” ASU 2011-11 will require entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the statement of financial position. The provisions of ASU 2011-11 are effective for us in interim and annual reporting periods beginning on or after January 1, 2013 and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows and financial position.

ASU 2011-08 “Intangibles – Goodwill and Other (Topic 350),” or ASU 2011-08 — In September 2011, the FASB issued ASU 2011-08, which amends Accounting Standards Codification, or ASC, Topic 350 “Intangibles — Goodwill and Other.” ASU 2011-08 provides additional guidance on the two-step test for goodwill impairment as previously described in Topic 350 “Intangibles — Goodwill and Other.” Under the new guidance, entities may elect to first assess qualitative factors instead of calculating the fair value of a reporting unit unless the entity determines that it is more likely than not the fair value of the reporting unit is less than its carrying value. This ASU is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. We elected to adopt ASU 2011-08 for our 2011 annual goodwill impairment test. There was no impact from the adoption of ASU 2011-08 on our consolidated results of operations, cash flows and financial position.

ASU 2011-04 “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, or ASU 2011-04 — In May 2011, the FASB issued ASU 2011-04 which amends ASC, Topic 820 “Fair Value Measurements and Disclosures” to change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, clarify the FASB’s intent about the application of existing fair value measurement requirements, and change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The provisions of ASU 2011-04 are effective for us for interim and annual periods beginning after December 15, 2011 and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows and financial position.

4. Acquisitions

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative instruments related to the Southeast Texas storage business, for aggregate consideration of $240.0 million, subject to certain working capital and other customary purchase price adjustments. $192.0 million of the aggregate purchase price was financed with a portion of the net proceeds from our 4.95% 10-year Senior Notes offering issued on March 13, 2012. The remaining $48.0 million consideration was financed by the issuance at closing of an aggregate of 1,000,417 of our common units. DCP Midstream, LLC also provided fixed price NGL commodity derivatives, valued at $39.5 million, for the three year period subsequent to closing the newly acquired interest. The $29.6 million deficit purchase price under the historical basis of the net assets acquired and the $48.0 million of common units issued as consideration for this acquisition were recorded as an increase in common unitholders equity. Prior to the acquisition of the additional interest in Southeast Texas, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method. The acquisition of the remaining 66.67% interest in Southeast Texas represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated financial statements have been adjusted to retrospectively include the historical results of our 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business for all periods presented, similar to the pooling method. These results are included in our Natural Gas Services segment.

14

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Combined Financial Information

The results of our 100% interest in Southeast Texas are included in the consolidated balance sheets as of December 31, 2011 and December 31, 2010. The following tables present the previously reported December 31, 2011 and December 31, 2010 consolidated balance sheets, adjusted for the acquisition of the remaining 66.67% interest in Southeast Texas from DCP Midstream, LLC:

As of December 31, 2011

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Southeast Texas (b)			Remove Southeast Texas Investment in Unconsolidated Affiliate (c)			Combined DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	6.7		$	0.9		$	—		$	7.6
Accounts receivable		161.4			53.4			—			214.8
Inventories		64.7			23.2			—			87.9
Other		7.1			36.3			—			43.4
Total current assets		239.9			113.8			—			353.7
Property, plant and equipment, net		1,181.8			317.6			—			1,499.4
Goodwill and intangible assets, net		255.8			43.3			—			299.1
Investments in unconsolidated affiliates		208.7			—			(101.6	)		107.1
Other non-current assets		17.4			0.7			—			18.1
Total assets	$	1,903.6		$	475.4		$	(101.6	)	$	2,277.4
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	269.2		$	111.3		$	—		$	380.5
Long-term debt		746.8			—			—			746.8
Other long-term liabilities		46.7			5.1			—			51.8
Total liabilities		1,062.7			116.4			—			1,179.1
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity		649.7			360.8			(103.4	)		907.1
Accumulated other comprehensive income		(21.2	)		(1.8	)		1.8			(21.2	)
Total partners’ equity		628.5			359.0			(101.6	)		885.9
Noncontrolling interests		212.4			—			—			212.4
Total equity		840.9			359.0			(101.6	)		1,098.3
Total liabilities and equity	$	1,903.6		$	475.4		$	(101.6	)	$	2,277.4

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as investments in unconsolidated affiliates.

(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.

(c) Adjustments to remove Southeast Texas 33.33% investment in unconsolidated affiliates.

15

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

As of December 31, 2010

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Southeast Texas (b)			Remove Southeast Texas Investment in Unconsolidated Affiliate(c)			Combined DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	6.7		$	—		$	—		$	6.7
Accounts receivable		151.0			96.3			—			247.3
Inventories		64.1			9.5			—			73.6
Other		10.2			12.6			—			22.8
Total current assets		232.0			118.4			—			350.4
Property, plant and equipment, net		1,097.1			281.5			—			1,378.6
Goodwill and intangible assets, net		258.6			45.6			—			304.2
Investments in unconsolidated affiliates		216.9			—			(112.6	)		104.3
Other non-current assets		8.6			1.1			—			9.7
Total assets	$	1,813.2		$	446.6		$	(112.6	)	$	2,147.2
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	211.2		$	104.1		$	—		$	315.3
Long-term debt		647.8			—			—			647.8
Other long-term liabilities		103.4			4.7			—			108.1
Total liabilities		962.4			108.8			—			1,071.2
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity		658.4			340.5			(115.3	)		883.6
Accumulated other comprehensive income		(27.7	)		(2.7	)		2.7			(27.7	)
Total partners’ equity		630.7			337.8			(112.6	)		855.9
Noncontrolling interests		220.1			—			—			220.1
Total equity		850.8			337.8			(112.6	)		1,076.0
Total liabilities and equity	$	1,813.2		$	446.6		$	(112.6	)	$	2,147.2

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as investments in unconsolidated affiliates.

(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.

(c) Adjustments to remove Southeast Texas 33.33% investment in unconsolidated affiliates.

16

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

The results of our 100% interest in Southeast Texas are included in the consolidated statements of operations for the years ended December 31, 2011, December 31, 2010 and December 31, 2009. The following tables present the previously reported condensed consolidated statements of operations for the years ended December 31, 2011, December 31, 2010 and December 31, 2009, adjusted for the acquisition of the remaining 66.67% interest in Southeast Texas from DCP Midstream, LLC:

Year Ended December 31, 2011

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Southeast Texas (b)		Remove Southeast Texas Equity Earnings (c)			Combined DCP Midstream Partners, LP (As currently reported)
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	1,413.3		$	765.2	$	—		$	2,178.5
Transportation, processing and other		163.2			9.0		—			172.2
(Losses) gains from commodity derivative activity, net		(6.7	)		14.4		—			7.7
Total operating revenues		1,569.8			788.6		—			2,358.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,229.8			703.2		—			1,933.0
Operating and maintenance expense		105.4			20.3		—			125.7
Depreciation and amortization expense		81.0			19.6		—			100.6
General and administrative expense		37.3			11.0		—			48.3
Other income		(0.5	)		—		—			(0.5	)
Total operating costs and expenses		1,453.0			754.1		—			2,207.1
Operating income		116.8			34.5		—			151.3
Interest expense, net		(33.9	)		—		—			(33.9	)
Earnings from unconsolidated affiliates		36.9			—		(14.2	)		22.7
Income before income taxes		119.8			34.5		(14.2	)		140.1
Income tax (expense) benefit		(0.6	)		0.1		—			(0.5	)
Net income		119.2			34.6		(14.2	)		139.6
Net income attributable to noncontrolling interests		(18.8	)		—		—			(18.8	)
Net income attributable to partners	$	100.4		$	34.6	$	(14.2	)	$	120.8

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as earnings from unconsolidated affiliates.

(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.

(c) Adjustments to remove Southeast Texas equity earnings at 33.33%.

17

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Year Ended December 31, 2010

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Southeast Texas (b)			Remove Southeast Texas Equity Earnings (c)			Combined DCP Midstream Partners, LP (As currently reported)
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	1,162.7		$	812.4		$	—		$	1,975.1
Transportation, processing and other		115.3			15.0			—			130.3
(Losses) gains from commodity derivative activity, net		(8.5	)		11.5			—			3.0
Total operating revenues		1,269.5			838.9			—			2,108.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,032.6			750.5			—			1,783.1
Operating and maintenance expense		79.8			18.5			—			98.3
Depreciation and amortization expense		73.7			14.4			—			88.1
General and administrative expense		33.7			12.1			—			45.8
Gain on step acquisition		(9.1	)		—			—			(9.1	)
Other income		(4.0	)		(1.0	)		—			(5.0	)
Total operating costs and expenses		1,206.7			794.5			—			2,001.2
Operating income		62.8			44.4			—			107.2
Interest expense, net		(29.1	)		—			—			(29.1	)
Earnings from unconsolidated affiliates		38.2			—			(14.4	)		23.8
Income before income taxes		71.9			44.4			(14.4	)		101.9
Income tax expense		(0.3	)		(1.2	)		—			(1.5	)
Net income		71.6			43.2			(14.4	)		100.4
Net income attributable to noncontrolling interests		(9.2	)		—			—			(9.2	)
Net income attributable to partners	$	62.4		$	43.2		$	(14.4	)	$	91.2

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as earnings from unconsolidated affiliates.

(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.

(c) Adjustments to remove Southeast Texas equity earnings at 33.33%.

18

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Year Ended December 31, 2009

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Southeast Texas (b)			Remove Southeast Texas Equity Earnings (c)			Combined DCP Midstream Partners, LP (As currently reported)
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	913.0		$	516.3		$	—		$	1,429.3
Transportation, processing and other		95.2			9.7			—			104.9
(Losses) gains from commodity derivative activity, net		(65.8	)		9.5			—			(56.3	)
Total operating revenues		942.4			535.5			—			1,477.9
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		776.2			472.1			—			1,248.3
Operating and maintenance expense		69.7			14.5			—			84.2
Depreciation and amortization expense		64.9			12.0			—			76.9
General and administrative expense		32.3			10.8			—			43.1
Other income		—			0.5			—			0.5
Total operating costs and expenses		943.1			509.9			—			1,453.0
Operating (loss) income		(0.7	)		25.6			—			24.9
Interest expense, net		(28.0	)		—			—			(28.0	)
Earnings from unconsolidated affiliates		26.9			—			(8.4	)		18.5
(Loss) income before income taxes		(1.8	)		25.6			(8.4	)		15.4
Income tax expense		(0.6	)		(0.4	)		—			(1.0	)
Net (loss) income		(2.4	)		25.2			(8.4	)		14.4
Net income attributable to noncontrolling interests		(8.3	)		—			—			(8.3	)
Net (loss) income attributable to partners	$	(10.7	)	$	25.2		$	(8.4	)	$	6.1

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as earnings from unconsolidated affiliates.

(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.

(c) Adjustments to remove Southeast Texas equity earnings at 33.33%.

The currently reported results are not intended to reflect actual results that would have occurred if the acquired business had been combined during the period presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

On August 1, 2011, we reached an agreement with DCP Midstream, LLC for us to construct a 200 MMcf/d cryogenic natural gas processing plant, or the Eagle Plant, in the Eagle Ford shale which represents an investment of approximately $120.0 million. In support of our construction of the Eagle Plant, we entered into a 15 year fee-based processing agreement with an affiliate of DCP Midstream, LLC, which provides us with a fixed demand charge for 150 MMcf/d along with a throughput fee on all volumes processed. The processing agreement commences with commercial operations of the new plant, which is expected to be online by the fourth quarter of 2012. In conjunction with the agreement, we also entered into a purchase and sale agreement with DCP Midstream, LLC to purchase certain tangible assets and land located in the Eagle Ford Shale for $23.4 million, financed initially at closing with borrowings under the Partnership’s revolving credit facility.

19

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

On March 24, 2011, we acquired two NGL fractionation facilities in Weld County, Colorado, located in the Denver-Julesburg Basin, from a third party in a transaction accounted for as an asset acquisition. We paid a purchase price of $30.0 million, financed initially at closing with borrowings under the Partnership’s revolving credit facility, and received a post-closing purchase price adjustment of $0.4 million. The NGL fractionation facilities are located on DCP Midstream, LLC’s processing plant sites and are operated by DCP Midstream, LLC. Subsequent to our acquisition, DCP Midstream, LLC continues to operate and supply certain committed NGLs produced by them in Weld County to our DJ Basin NGL Fractionators under the existing agreements that are effective through March 2018. The results of the assets are included in our NGL Logistics segment prospectively, from the date of acquisition.

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, financed initially at closing with proceeds from our November 2010 public equity offering and borrowings under the Partnership’s revolving credit facility. DCP Midstream, LLC’s historical carrying value of the net assets acquired was $114.3 million; accordingly we have recorded the $35.7 million excess purchase price over acquired assets as a decrease in common unitholders equity.

On December 30, 2010, we acquired all of the interests in Marysville. The acquisition involved three separate transactions with a number of parties. We 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 owned the remaining 5% interest in Marysville. We paid a purchase price of $94.8 million plus $6.0 million for net working capital and other adjustments for an aggregate purchase price of $100.8 million, subject to customary purchase price adjustments, for our 100% interest. The cash purchase was financed initially at closing with borrowings under the Partnership’s revolving credit facility. $21.2 million of the purchase price was deposited in an indemnity escrow to satisfy certain tax liabilities and provide for breaches of representations and warranties of the sellers. $19.5 million remains in the escrow account after $1.7 million was released on June 15, 2011. The results of the Marysville acquisition are included in our NGL Logistics segment prospectively, from the date of acquisition.

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 triggered 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 tax liabilities of Marysville for which an indemnity escrow has been established. During 2011, we made federal and state tax payments of $29.3 million and $0.3 million, respectively, related to our estimated $35.0 million tax liability that resulted from our acquisition of Marysville. The remaining $5.4 million estimated tax payable has been reclassified to goodwill in our final accounting for the Marysville business combination.

We have updated our accounting for the Marysville business combination for the fair value of assets acquired and liabilities assumed including intangible assets, property, plant and equipment and goodwill. The purchase price allocation as of December 31, 2011 is as follows:

	December 31, 2011
	(Millions)
Aggregate consideration	$	100.8
Cash		3.1
Accounts receivable		0.3
Inventory		4.6
Other current assets		0.7
Property, plant and equipment		57.1
Intangible assets		33.0
Goodwill		34.7
Other long-term assets		1.2
Other current liabilities		(4.3	)
Long-term liabilities		(29.6	)
Total purchase price allocation	$	100.8

The results of operations for acquisitions accounted for as a business combination are included in the DCP Midstream Partners, LP results subsequent to the date of acquisition. Accordingly, for the year ended December 31, 2011 total operating revenues of $26.7 million, and net income attributable to the Partnership of $12.6 million, associated with Marysville, are included in the consolidated statement of operations. Pro forma information is presented for comparative periods prior to the date of acquisition, however, comparative periods in the consolidated financial statements are not adjusted to include the results of the acquisition.

20

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

The following table presents unaudited pro forma information for the consolidated statement of operations for the year ended December 31, 2010, as if the acquisition of Marysville had occurred at the beginning of the period presented.

	Year Ended December 31, 2010
	DCP Midstream Partners, LP			Acquisition  of Marysville			DCP Midstream Partners, LP Pro Forma
	(Millions, except per unit amounts)
Total operating revenues	$	2,108.4		$	23.2		$	2,131.6
Net income attributable to partners		91.2			8.2			99.4
Less:
Net income attributable to predecessor operations		(43.2	)		—			(43.2	)
General partner unitholders interest in net income		(16.9	)		(0.1	)		(17.0	)
Net income allocable to limited partners	$	31.1		$	8.1		$	39.2
Net income per limited partner unit — basic and diluted	$	0.86		$	0.22		$	1.08

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

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Omnibus Agreement and Other General and Administrative Charges

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

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,
	2011		2010		2009
	(Millions)
Omnibus Agreement	$	10.2	$	9.9	$	9.7
Other fees — DCP Midstream, LLC		18.9		21.4		21.2
Total — DCP Midstream, LLC	$	29.1	$	31.3	$	30.9

21

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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. We also pay DCP Midstream, LLC for certain costs incurred and 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. 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.

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).

East Texas and Southeast Texas incur general and administrative expenses directly from DCP Midstream, LLC. During the years ended December 31, 2011, 2010 and 2009, East Texas incurred $7.5 million, $7.8 million and $8.5 million, respectively, and during the years ended December 31, 2011, 2010 and 2009, Southeast Texas incurred $10.0 million, $12.1 million and $10.8 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations. General and administrative expenses incurred by East Texas and Southeast Texas effective January 3, 2012 and March 30, 2012, respectively, will be included in the Omnibus Agreement.

In addition to the Omnibus Agreement and amounts incurred by East Texas and Southeast Texas, we incurred other fees with DCP Midstream, LLC, which includes expenses for our predecessor operations, of $1.4 million, $1.5 million and $1.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

Competition

None of DCP Midstream, LLC, 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.

Other Agreements and Transactions with DCP Midstream, LLC

DCP Midstream, LLC was a significant customer during the years ended December 31, 2011, 2010 and 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 and services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf. We have and may continue to enter into market based derivative transactions directly with DCP Midstream, LLC, whereby DCP Midstream is the counterparty.

We have a contractual arrangement with DCP Midstream, LLC, through March 2022, in which we pay DCP Midstream, LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing 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 purchases of natural gas, propane, NGLs and condensate from affiliates. In addition, as part of this arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates.

22

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system, included in our Northern Louisiana system, which is part of our Natural Gas Services segment, that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under a firm transportation agreement with an affiliate, effective through January 31, 2012. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand are sold to DCP Midstream, LLC at an index-based price, less contractually agreed to marketing fees. Revenues associated with these activities are reported gross in our consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

On August 1, 2011, we reached an agreement with DCP Midstream, LLC for us to construct a 200 MMcf/d cryogenic natural gas processing plant, in the Eagle Ford shale which represents an investment of approximately $120.0 million. In support of our construction of the Eagle Plant, we entered into a 15 year fee-based processing agreement with an affiliate of DCP Midstream, LLC, which provides us with a fixed demand charge for 150 MMcf/d along with a throughput fee on all volumes processed. The processing agreement commences with commercial operations of the new plant, which is expected to be online by the fourth quarter of 2012. In conjunction with the agreement, we also entered into a purchase and sale agreement with DCP Midstream, LLC to purchase certain tangible assets and land located in the Eagle Ford Shale for $23.4 million.

On November 4, 2011, we entered into agreements with DCP Midstream, LLC, to acquire the remaining 49.9% interest in East Texas for aggregate consideration of $165.0 million, subject to certain working capital and other customary purchase price adjustments. Prior to the contribution of the additional interest in East Texas, we owned a 50.1% interest which we account for as a consolidated subsidiary. The contribution of the remaining 49.9% interest in East Texas represents a transaction between entities under common control, but does not represent a change in reporting entity. Accordingly, we will include the results of the remaining 49.9% interest in East Texas prospectively from the date of acquisition. This acquisition closed on January 3, 2012.

During the year ended December 31, 2011, East Texas received $7.8 million in business interruption recoveries related to the first quarter 2009 fire that was caused by a third party underground pipeline rupture outside of our property, or the East Texas recovery settlement. We have allocated the recoveries based upon relative ownership percentages at the time the losses were incurred, factoring in amounts previously reimbursed to us by DCP Midstream, LLC. For the year ended December 31, 2011, we recorded $6.6 million to our consolidated statement of operations in “sales of natural gas, propane, NGLs and condensate”, with $4.6 million representing DCP Midstream, LLC’s portion in “net income attributable to noncontrolling interests.”

In conjunction with our January 1, 2011 acquisition of the initial 33.33% interest in Southeast Texas from DCP Midstream, LLC for $150.0 million in our Natural Gas Services segment, we entered into a joint venture agreement. The terms of the joint venture agreement provided that distributions and earnings to us for the first seven years related to storage and transportation gross margin would be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions and earnings related to the gathering and processing business, along with reductions for all expenditures, would be pursuant to our and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas for aggregate consideration of $240.0 million. As we now own 100% of the interests in Southeast Texas, the joint venture agreement is no longer in effect.

In conjunction with our acquisition of a 50.1% limited liability company interest in East Texas (25.0% of which was acquired in July 2007, and 25.1% in April 2009), which is part of our Natural Gas Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain expenditures on East Texas capital projects. 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 $18.3 million and $13.8 million for the years ended December 31, 2011 and 2010, respectively.

On September 16, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment at Collbran, part of our Natural Gas Services segment, 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 were distributed 75% to us and 25% to the noncontrolling interest in Collbran, based upon proportionate ownership, during the year ended December 31, 2010. The sale was completed when title to the surplus equipment passed to DCP Midstream, LLC in March 2011. We have recognized a distribution of $2.6 million for year ended December 31, 2011 to 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.

23

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

In our Natural Gas Services segment, we sell NGLs processed at certain of our 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 transportation, processing and other charges from the tailgate of the respective asset.

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

In conjunction with our acquisition of 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, which 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 associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates.

In conjunction with our acquisition of our DJ Basin NGL Fractionators in our NGL Logistics segment, we pay a fee to DCP Midstream, LLC to operate our DJ Basin NGL Fractionators and receive fees for the processing of DCP Midstream, LLC’s committed NGLs produced by them in Weld County at our DJ Basin NGL Fractionators under agreements that are effective through March 2018. During the year ended December 31, 2011 we incurred fees $0.6 million, which are included in operating and maintenance expense in the consolidated statements of operations.

DCP Midstream, LLC has issued parental guarantees, totaling $70.0 million as of December 31, 2011, in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC interest of 0.5% per annum on these outstanding guarantees.

DCP Midstream, LLC has issued parental guarantees for its 49.9% limited liability company interest in East Texas, totaling $6.0 million as of December 31, 2011, in favor of certain counterparties to processing and transportation agreements at East Texas. Concurrently, we issued similar guarantees for our 50.1% interest. On January 3, 2012, we completed the acquisition of the remaining 49.9% interest in East Texas from DCP Midstream.

Spectra Energy

We have a propane supply agreement with Spectra Energy, effective from May 1, 2008 through April 30, 2012, which provides us propane supply at our marine terminals, which are included in our Wholesale Propane Logistics segment, for up to approximately 185 million gallons of propane annually. We are currently assessing several available options for future supply sources.

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.

ConocoPhillips

We have multiple agreements with ConocoPhillips and its affiliates. The agreements include fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $0.1 million, $0.2 million and $0.6 million of capital reimbursements during the years ended December 31, 2011, 2010 and 2009, respectively.

24

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:

	Year Ended December 31,
	2011		2010			2009
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	1,058.7	$	881.2		$	667.9
Transportation, processing and other	$	26.0	$	12.1		$	7.5
Purchases of natural gas, propane and NGLs	$	185.8	$	183.9		$	138.8
Gains (losses) from commodity derivative activity, net	$	0.2	$	(1.9	)	$	(3.6	)
Operating and maintenance expense	$	0.6	$	—		$	—
General and administrative expense	$	29.1	$	31.3		$	30.9
Interest expense	$	0.4	$	0.2		$	0.2
Spectra Energy:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	0.3
Transportation, processing and other	$	—	$	0.2		$	0.3
Purchases of natural gas, propane and NGLs (a)	$	249.6	$	82.1		$	95.3
Operating and maintenance expense	$	—	$	(0.3	)	$	0.2
Other income	$	—	$	3.0		$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	52.2	$	43.0		$	30.4
Transportation, processing and other	$	7.4	$	9.9		$	8.2
Purchases of natural gas, propane and NGLs	$	5.8	$	7.4		$	12.8
General and administrative expense	$	0.3	$	0.2		$	0.3
(Losses) gains from commodity derivative activity, net	$	—	$	(0.4	)	$	0.7
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	6.0	$	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.

We had balances with affiliates as follows:

	December 31,
	2011			2010
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	100.0		$	98.7
Accounts payable	$	22.6		$	27.0
Unrealized gains on derivative instruments—current	$	0.6		$	1.3
Unrealized losses on derivative instruments—current	$	(0.6	)	$	(1.8	)
Unrealized losses on derivative instruments—long term	$	(2.6	)	$	—
Spectra Energy:
Accounts receivable	$	0.1		$	0.3
Accounts payable	$	21.4		$	8.7
ConocoPhillips:
Accounts receivable	$	6.1		$	7.9
Accounts payable	$	0.4		$	1.0
Unrealized gains on derivative instruments—current	$	2.5		$	0.1
Unrealized losses on derivative instruments—current	$	(2.0	)	$	(0.3	)
Unconsolidated affiliates:
Accounts payable	$	2.4		$	0.9

25

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

6. Property, Plant and Equipment

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

	Depreciable		December 31,
	Life		2011			2010
			(Millions)
Gathering and transmission systems		15 — 30 Years	$	1,191.9		$	1,167.8
Processing, storage and terminal facilities		20 — 50 Years		764.3			734.6
Other		0 — 30 Years		21.6			14.9
Construction work in progress				218.3			66.3
Property, plant and equipment				2,196.1			1,983.6
Accumulated depreciation				(696.7	)		(605.0	)
Property, plant and equipment, net			$	1,499.4		$	1,378.6

Interest capitalized on construction projects in 2011, 2010 and 2009, was $1.6 million, $0.2 million and $1.3 million, respectively.

Depreciation expense was $92.2 million, $83.2 million and $74.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Asset Retirement Obligations — As of December 31, 2011, we had asset retirement obligations of $12.4 million included in other long-term liabilities in the consolidated balance sheets. As of December 31, 2010 we had asset retirement obligations of $11.7 million included in other long-term liabilities in the consolidated balance sheets. Accretion expense for the years ended December 31, 2011, 2010 and 2009 was $0.7 million, $0.7 million and $0.4 million, 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, 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 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. Goodwill and Intangible Assets

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

	December 31,
	2011		2010
	(Millions)
Beginning of period	$	151.2	$	92.1
Acquisitions		2.6		59.1
End of period	$	153.8	$	151.2

The carrying value of goodwill was $82.2 million and $74.7 million as of December 31, 2011 and December 31, 2010 respectively, for our Natural Gas Services segment, $36.9 million as of both periods for our Wholesale Propane Logistics segment, and $34.7 million and $39.6 million as of December 31, 2011 and December 31, 2010 respectively, for our NGL logistics segment.

Goodwill increased in 2011 by $2.6 million as a result of a $7.5 million increase related to a purchase price adjustment for a contingent payment in conjunction with our 2008 Michigan System acquisition; partially offset by a decrease of $4.9 million related to a purchase price adjustment of our Marysville acquisition.

26

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Our annual goodwill impairment tests, including our qualitative analysis, indicated that our reporting units’ fair value exceeded the carrying or book value. 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.

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,
	2011			2010
	(Millions)
Gross carrying amount	$	164.3		$	163.6
Accumulated amortization		(19.0	)		(10.6	)
Intangible assets, net	$	145.3		$	153.0

For the years December 31, 2011, 2010 and 2009, we recorded amortization expense of $8.4 million, $4.9 million and $2.6 million, respectively. As of December 31, 2011, the remaining amortization periods ranged from approximately 10 years to 24 years, with a weighted-average remaining period of approximately 18 years.

Estimated future amortization for these intangible assets is as follows:

Estimated Future Amortization
(Millions)
2012	$	8.4
2013		8.4
2014		8.4
2015		8.4
2016		8.4
Thereafter		103.3
Total	$	145.3

27

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

8. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

	Percentage of Ownership as of December 31,	Carrying Value as  of December 31,
	2011 and 2010	2011		2010
		(Millions)
Discovery Producer Services, LLC	40%	$	106.9	$	104.1
Other	50%		0.2		0.2
Total investments in unconsolidated affiliates		$	107.1	$	104.3

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $32.6 million and $35.1 million at December 31, 2011 and 2010, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

Earnings from investments in unconsolidated affiliates were as follows:

	Year Ended December 31,
	2011		2010		2009
	(Millions)
Discovery Producer Services LLC	$	22.7	$	23.0	$	16.6
Other (a)		—		0.8		1.9
Total earnings from unconsolidated affiliates	$	22.7	$	23.8	$	18.5

(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 and accordingly, earnings from unconsolidated affiliates excludes the results of Black Lake since July 30, 2010.

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

	Year Ended December 31,
	2011(a)		2010 (a)(b)		2009(b)
	(Millions)
Statements of operations:
Operating revenue	$	210.7	$	211.6	$	168.1
Operating expenses	$	159.9	$	156.7	$	127.2
Net income	$	50.8	$	52.7	$	40.4

(a) The combined financial information excludes the results of Black Lake since we began accounting for Black Lake as a consolidated subsidiary on July 30, 2010.

(b) The combined financial information includes the results of Southeast Texas, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	December 31,
	2011 (a)			2010 (a)
	(Millions)
Balance sheet:
Current assets	$	38.1		$	35.2
Long-term assets		359.9			356.7
Current liabilities		(20.4	)		(17.8	)
Long-term liabilities		(28.5	)		(25.6	)
Net assets	$	349.1		$	348.5

(a) The combined financial information excludes the results of Black Lake since we began accounting for Black Lake as a consolidated subsidiary effective July 30, 2010.

9. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

• Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

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

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

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 12 Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

• Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

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

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

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

Commodity Derivative Assets and Liabilities

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

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

Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a

30

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

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

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 as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

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

31

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

The following table presents the financial instruments carried at fair value as of December 31, 2011 and 2010, by consolidated balance sheet caption and by valuation hierarchy, as described above:

	December 31, 2011											December 31, 2010
	Level 1		Level 2			Level 3			Total Carrying Value			Level 1		Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets (a):
Commodity derivatives	$	—	$	40.1		$	1.1		$	41.2		$	—	$	14.2		$	0.3		$	14.5
Interest rate derivatives	$	—	$	—		$	—		$	—		$	—	$	—		$	—		$	—
Long-term assets (b):
Commodity derivatives	$	—	$	5.4		$	1.0		$	6.4		$	—	$	1.6		$	0.3		$	1.9
Current liabilities (c):
Commodity derivatives	$	—	$	(43.1	)	$	(0.7	)	$	(43.8	)	$	—	$	(39.5	)	$	(0.1	)	$	(39.6	)
Interest rate derivatives	$	—	$	(16.1	)	$	—		$	(16.1	)	$	—	$	(17.0	)	$	—		$	(17.0	)
Acquisition related contingent consideration (d)	$	—	$	—		$	—		$	—		$	—	$	—		$	(2.1	)	$	(2.1	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(27.5	)	$	(0.3	)	$	(27.8	)	$	—	$	(40.1	)	$	(0.5	)	$	(40.6	)
Interest rate derivatives	$	—	$	(5.0	)	$	—		$	(5.0	)	$	—	$	(9.9	)	$	—		$	(9.9	)

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

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

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

(d) Included in other current liabilities in our consolidated balance sheets.

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

Changes in Level 3 Fair Value Measurements

The tables below 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.

32

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(Millions)
Year ended December 31, 2011 (a):
Beginning balance	$	0.3		$	0.3		$	(0.1	)	$	(0.5	)
Net realized and unrealized gains (losses) included in earnings		1.4			0.8			(0.8	)		0.2
Transfers into Level 3 (b)		—			—			—			—
Transfers out of Level 3 (b)		—			(0.1	)		—			—
Settlements		(0.6	)		—			0.2			—
Ending balance	$	1.1		$	1.0		$	(0.7	)	$	(0.3	)
Net unrealized gains (losses) still held included in earnings (c)	$	1.1		$	0.7		$	(0.7	)	$	0.1
Year ended December 31, 2010:
Beginning balance	$	1.2		$	0.7		$	(1.6	)	$	(0.7	)
Net realized and unrealized gains (losses) included in earnings		2.1			0.8			(0.3	)		0.2
Transfers into Level 3 (b)		—			—			—			—
Transfers out of Level 3 (b)		(0.5	)		—			0.3			—
Purchases, Issuances and Settlements net		(2.5	)		(1.2	)		1.5			—
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	$	0.5		$	1.7		$	—		$	—
Net realized and unrealized gains (losses) included in earnings		1.2			(1.0	)		(4.7	)		(0.7	)
Net transfers (out) of Level 3 (b)		(0.1	)		—			—			—
Purchases, Issuances and Settlements net		(0.4	)		—			3.1			—
Ending balance	$	1.2		$	0.7		$	(1.6	)	$	(0.7	)
Net unrealized gains (losses) still held included in earnings (c)	$	1.3		$	0.4		$	(2.6	)	$	(0.7	)

(a) There were no purchases, issuances and sales for the year ended December 31, 2011.

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

(c) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of December 31, 2011, 2010 and 2009.

33

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

During the year ended December 31, 2011, we settled a $2.1 million contingent consideration, which was classified as Level 3, associated with the Southeast Texas acquisition of the Raywood processing plant and Liberty gathering system from Ceritas in June 2010. During the year ended December 31, 2010, we recognized the fair value of contingent consideration of $3.1 million in relation to this acquisition, which was recorded to other current liabilities in our consolidated balance sheets. During the year ended December 31, 2010, we reassessed the $3.1 million fair value of the contingent consideration and adjusted the liability to $2.1 million. Accordingly, we recognized approximately $1.0 million in other income in our consolidated results of operations during the year ended December 31, 2010.

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 approximately $1.0 million, which we recorded to other current liabilities in our consolidated balance sheets. Subsequent to the first quarter of 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0, and accordingly, we recognized $1.0 million in other income in our consolidated results of operations during the year ended December 31, 2010.

During years ended December 31, 2011 and 2010, we had no significant transfers into or out of Levels 1 and 2. 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 assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of 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 $497.0 million and $497.0 million as of December 31, 2011 and $398.0 million and $388.9 million, respectively as of December 31, 2010. The carrying value of the 3.25% Senior Notes is $250.0 million as of December 31, 2011 and 2010, which approximates fair value. We determine the fair value of our credit facility borrowings based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We determine the fair value of our fixed-rate debt based on quotes obtained from bond dealers.

11. Debt

Long-term debt was as follows:

	December 31, 2011			December 31, 2010
	(Millions)
Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.69% and 1.14%, respectively, and net effective interest rate of 4.86% and 4.28%, respectively, due November 10, 2016 (a)	$	497.0		$	398.0
Debt Securities
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015		250.0			250.0
Unamortized discount		(0.2	)		(0.2	)
Total long-term debt	$	746.8		$	647.8

(a) $450.0 million of debt has been swapped to a fixed-rate obligation with effective fixed-rates ranging from 2.94% to 5.19%, for a net effective rate of 4.86% on the $497.0 million of outstanding debt under our revolving credit facility as of December 31, 2011.

34

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Credit Agreement

On November 10, 2011, we entered into a Credit Agreement providing for a $1.0 billion revolving credit facility that matures November 10, 2016. The Credit Agreement replaced our Amended and Restated Credit Agreement dated as of June 21, 2007 (the Prior Credit Agreement), which had a total borrowing capacity of $850.0 million and would have matured on June 21, 2012. The initial borrowing under the Credit Agreement was used to repay the Company’s indebtedness under the Prior Credit Agreement. The revolving credit facility provided by the Credit Agreement will be used for ongoing working capital requirements and for other general partnership purposes including acquisitions.

At December 31, 2011 and 2010, we had $1.1 million and $32.1 million, respectively, of letters of credit issued and outstanding under the Credit Agreement and the Prior Credit Agreement. As of December 31, 2011, the unused capacity under the revolving credit facility was $501.9 million, of which approximately $279.5 million was available for general working capital. We incurred $3.9 million of debt issuance costs 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, 2011 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 November 10, 2016 maturity date.

Under the Credit Agreement, indebtedness under the revolving credit facility bears interest at either (1) LIBOR, plus an applicable margin ranging from 0.85% to 1.65% depending on our credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin ranging from 0% to 0.65% depending on our credit rating. The revolving credit facility incurs an annual facility fee of 0.15% to 0.35% depending on our credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

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.

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 expenses and unamortized discounts of $1.5 million, $0.6 million and $0.2 million, respectively, which we used to repay funds borrowed under the revolver portion of the Prior Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year, with the first payment made on April 1, 2011. The notes will mature on October 1, 2015, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.

The notes are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness, including indebtedness under our Credit Agreement. 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.

The future maturities of long-term debt in the year indicated are as follows:

	Debt Maturities
	(Millions)
2012	$	—
2013		—
2014		—
2015		250.0
Thereafter		497.0
Unamortized discount		(0.2	)
Total	$	746.8

35

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Other Agreements

As of December 31, 2011, we had a contingent letter of credit for up to $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. As of December 31, 2011, we had no letters of credit issued on this facility; any letters of credit issued on this facility will incur a fee of 1.75% per annum and 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

Cash Flow Protection Activities — 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, processing and storage services, we may receive cash 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 2016 with commodity derivative instruments. Given the limited liquidity and tenor of the NGL derivatives market, we have primarily utilized crude oil swaps and costless collars to mitigate a portion of our commodity price exposure for NGLs. For the nearer tenor where there is greater liquidity in the NGL derivatives market, we have periodically also utilized NGL derivatives. 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. 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. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. 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.

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 any change in fair 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.

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

36

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

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 accumulated other comprehensive income, or AOCI, relative to cash flow hedges were reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impacted earnings.

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative instruments related to the Southeast Texas storage business. During 2011, Southeast Texas commenced an expansion project to build an additional storage cavern. Upon completion of the expansion project, Southeast Texas will be required to purchase a significant amount of base gas to bring the storage cavern to operation. To mitigate risk associated with this forecasted purchase of natural gas, Southeast Texas executed a series of derivative financial instruments, which have been designated as cash flow hedges. These cash flow hedges were in a loss position of $5.3 million as of December 31, 2011 and will fluctuate in value through the term of construction. Any effective changes in fair value of these derivative instruments will be deferred in AOCI until the underlying purchase of inventory occurs. While the cash paid or received upon settlement of these hedges will economically offset the cash required to purchase the base gas, following completion of the additional storage cavern, any deferred gain or loss at the time of the purchase will remain in AOCI until the cavern is emptied and the base gas is sold.

In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. To mitigate the risk associated with the forecasted re-purchase of base gas, in 2008 we executed a series of derivative financial instruments, which were designated as cash flow hedges. The cash paid upon settlement of these hedges economically offsets the cash paid to purchase the base gas. As a result, a deferred loss of $2.7 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

Interest Rate Risk

We mitigate a portion of our interest rate risk with interest rate swaps and forward-starting interest rate swaps that reduce our exposure to market rate fluctuations by converting variable interest rates on our existing debt to fixed interest rates and locking in rates on our anticipated future fixed-rate debt, respectively. The 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. The forward-starting interest rate swap agreements lock in the interest rate associated with our anticipated future fixed-rate debt, thereby reducing the exposure to market rate fluctuations prior to issuance.

At December 31, 2011, we had interest rate swap agreements totaling $450.0 million, of which we have designated $425.0 million as cash flow hedges and account for the remaining $25.0 million under the mark-to-market method of accounting. As we generally expect to have variable-rate debt levels equal to or exceeding our swap positions during their term, the entire $450.0 million of these arrangements 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 mitigate our interest rate risk associated with our variable-rate debt.

At December 31, 2011, we had forward-starting interest rate swap agreements totaling $195.0 million, which we have designated as cash flow hedges. As we anticipate entering into future fixed-rate debt at levels equal to or exceeding our forward-

37

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

starting swap positions during their term, the entire $195.0 million of these arrangements mitigate a portion of our interest rate risk through the term of our anticipated debt into 2022. Based on our current operations we believe our forward-starting interest rate swap agreements mitigate a portion of our interest rate risk associated with our anticipated future fixed-rate debt.

Effectiveness of our interest rate swap agreements designated as cash flow hedges 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 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.

At December 31, 2011, $275.0 million of the interest rate swap agreements reprice prospectively approximately every 90 days and the remaining $175.0 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. Under the terms of the forward-starting interest rate swap agreements, we will pay fixed-rates ranging from 2.15% to 2.598%, and receive interest payments approximating 10-year U.S. Treasury rates. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense.

Contingent Credit Features

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

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

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

• 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, 2011, 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, 2011, we had $52.9 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2011 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, 2011, 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 $46.0 million.

38

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

As of December 31, 2011, we had $21.1 million of individual interest rate swap instruments that were in a net liability position and were 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, 2011, 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 $70.0 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, 2011, 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, 2011			December 31, 2010
	(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(1.8	)	$	(0.3	)
Interest rate cash flow hedges:
Net deferred losses in AOCI		(19.4	)	$	(27.4	)
Total AOCI	$	(21.2	)	$	(27.7	)

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, 2011		December 31, 2010		Balance Sheet Line Item	December 31, 2011			December 31, 2010
	(Millions)					(Millions)
Derivative Assets Designated as Hedging Instruments:					Derivative Liabilities Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments – current	$	—	$	—	Unrealized losses on derivative instruments – current	$	—		$	—
Unrealized gains on derivative instruments – long-term		—		—	Unrealized losses on derivative instruments – long-term		(2.6	)		—
	$	—	$	—		$	(2.6	)	$	—
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments – current	$	—	$	—	Unrealized losses on derivative instruments – current	$	(15.7	)	$	(12.2	)
Unrealized gains on derivative instruments – long-term		—		—	Unrealized losses on derivative instruments – long-term		(5.0	)		(5.4	)
	$	—	$	—		$	(20.7	)	$	(17.6	)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments – current	$	41.2	$	14.5	Unrealized losses on derivative instruments – current	$	(43.8	)	$	(39.6	)
Unrealized gains on derivative instruments – long-term		6.4		1.9	Unrealized losses on derivative instruments – long-term		(25.2	)		(40.6	)
	$	47.6	$	16.4		$	(69.0	)	$	(80.2	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments – current	$	—	$	—	Unrealized losses on derivative instruments – current	$	(0.4	)	$	(4.8	)
Unrealized gains on derivative instruments – long-term		—		—	Unrealized losses on derivative instruments – long-term		—			(4.5	)
	$	—	$	—		$	(0.4	)	$	(9.3	)

39

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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
	2011			2010			2011			2010			2011			2010			12 Months
	(Millions)						(Millions)						(Millions)						(Millions)
Interest rate derivatives	$	(12.4	)	$	(18.7	)	$	(20.4	)	$	(22.4	)(a)	$	(0.2	)	$	—	(a)(c)	$	(12.1	)
Commodity derivatives	$	(0.9	)	$	—		$	(0.3	)	$	(0.5	)(b)	$	—		$	—	(b)(c)	$	—

(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 years ended December 31, 2011 and 2010, 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.

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	2011			2010			2009
	(Millions)
Third party:
Realized	$	(36.4	)	$	15.9		$	26.3
Unrealized		43.2			(10.6	)		(79.7	)
Gains (losses) from commodity derivative activity, net	$	6.8		$	5.3		$	(53.4	)
Affiliates:
Realized	$	1.7		$	(1.2	)	$	—
Unrealized		(0.8	)		(1.1	)		(2.9	)
Gains (losses) from commodity derivative activity, net — affiliates	$	0.9		$	(2.3	)	$	(2.9	)
	Year Ended December 31,
Interest Rate Derivatives: Statements of Operations Line Item	2011			2010			2009
	(Millions)
Third party:
Realized	$	(4.6	)	$	(1.5	)	$	—
Unrealized		5.2			3.1			—
Interest expense	$	0.6		$	1.6		$	—

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

40

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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, 2011
	Crude Oil			Natural Gas			Natural Gas Liquids			Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)			Net Long (Short) Position (MMBtu)			Net (Short) Position (Bbls)			Net Long Position (MMBtu)
2012		(695,792	)		(17,766,000	)		(478,236	)		14,357,500
2013		(941,323	)		1,635,000			—			3,600,000
2014		(547,500	)		(365,000	)		—			—
2015		(365,000	)		—			—			—
2016		(183,000	)		—			—			—
	December 31, 2010
	Crude Oil			Natural Gas			Natural Gas Liquids			Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)			Net (Short) Position (MMBtu)			Net (Short) Position (Bbls)			Net Long Position (MMBtu)
2011		(998,554	)		(7,960,000	)		(73,190	)		6,025,000
2012		(839,358	)		(366,000	)		—			8,220,000
2013		(748,250	)		(365,000	)		—			—
2014		(547,500	)		(365,000	)		—			—
2015		(182,500	)		—			—			—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of December 31, 2011, we have swaps with notional values between $25.0 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, as defined below, to unitholders of record on the applicable record date, as determined by our general partner.

On August 17, 2011, we entered into an equity distribution agreement with Citigroup Global Markets Inc., or Citi. The agreement provides for the offer and sale from time to time through Citi, our sales agent, common units having an aggregate offering amount of up to $150.0 million. During the year ended December 31, 2011, we issued 761,285 of our common units pursuant to this equity distribution agreement. We received proceeds of $30.2 million from the issuance of these common units, net of commissions and offering costs of $1.2 million, which were used to finance growth opportunities.

In March 2011, we issued 3,596,636 common limited partner units at $40.55 per unit. We received proceeds of $139.7 million, net of offering costs.

In February 2011, we issued 8,399 common limited partner units, from our LTIP to employees as compensation for their service during 2010, 2009 and 2008.

In November 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.

41

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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

In November 2009, we 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 natural gas liquids derivative by NGL component for the period April 2009 to March 2010. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

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

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

• provide for the proper conduct of our business;

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

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

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

General Partner Interest and Incentive Distribution Rights — The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1% as of December 31, 2011. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common limited partner unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

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

Subordinated Units — All of our subordinated units were held by DCP Midstream, 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.

42

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Our partnership agreement provides that, during the subordination period, the common units 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 were not entitled to receive any distributions until the common units received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages 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.

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.

The following table presents our cash distributions paid in 2011, 2010 and 2009:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 14, 2011	$	0.6400	$	34.9
August 12, 2011	$	0.6325	$	34.0
May 13, 2011	$	0.6250	$	33.4
February 14, 2011	$	0.6175	$	30.0
November 12, 2010	$	0.6100	$	27.4
August 13, 2010	$	0.6100	$	25.3
May 14, 2010	$	0.6000	$	24.6
February 12, 2010	$	0.6000	$	24.6
November 13, 2009	$	0.6000	$	22.6
August 14, 2009	$	0.6000	$	22.6
May 15, 2009	$	0.6000	$	20.1
February 13, 2009	$	0.6000	$	20.1

14. Equity-Based Compensation

Total compensation cost for equity-based arrangements was as follows:

	Year Ended December 31,
	2011		2010		2009
	(Millions)
Performance Units	$	4.2	$	1.2	$	1.2
Phantom Units		0.2		0.2		0.4
Restricted Phantom Units		2.2		1.4		0.6
Total compensation cost	$	6.6	$	2.8	$	2.2

43

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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. 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.

Prior to February 18, 2011, substantially all equity-based awards were accounted for as liability awards. Effective February 18, 2011, the Modification Date, we have the intent and ability to settle certain awards within our control in units and therefore modified the accounting for these awards. We now classify them as equity awards based on their re-measured fair value. The fair value was determined based on the closing price of our common units on the Modification Date. Such modification resulted in a reclassification of $1.9 million from share-based compensation liability to additional paid-in capital on the Modification Date. Compensation expense on unvested equity awards as of the Modification Date will be recognized ratably over each remaining vesting period.

We will continue to account for other awards, which are subject to settlement in cash, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date.

The reclassification of the affected awards does not impact our accounting for dividend equivalent rights as these instruments will continue to be settled in cash and therefore retain their share-based compensation liability classification.

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 performance periods. The final performance payout is determined by the compensation committee of the board of directors of our General Partner. The DERs are paid in cash at the end of the performance period. Of the remaining Performance Units outstanding at December 31, 2011, 11,641 units are expected to vest on December 31, 2012 and 7,406 units are expected to vest on December 31, 2013.

At December 31, 2011, there was approximately $0.4 million of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of 2 years. The following table presents information related to the Performance Units:

	Units			Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2009		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		(14,215	)	$	33.44
Forfeited		(2,205	)	$	15.61
Outstanding at December 31, 2010		67,350		$	15.42
Granted		10,580		$	41.80
Vested (a)		(50,720	)	$	10.05
Forfeited		—		$	—
Outstanding at December 31, 2011		27,210		$	35.69	$	47.47
Expected to vest (b)		19,047		$	35.69	$	47.47

(a) The units vested at 199%.

(b) Based on our December 31, 2011 estimated achievement of specified performance targets, the performance estimate for units granted in 2011 is 100%, and for units granted in 2010 is 100%. The estimated forfeiture rate for units granted in 2011 is 30% and for units granted in 2010 is 30%.

44

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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:

	Year Ended December 31,
	2011		2010 (a)		2009
	(Millions)
Fair value of units vested	$	5.3	$	—	$	1.1
Unit-based liabilities paid	$	—	$	0.8	$	0.3

(a) The liabilities paid in 2010 relate to 22,860 units and DERs that vested in 2009. The remaining units that vested in 2009 were paid in 2009.

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.

In 2011, 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 2011. All of these units vested in 2011and were settled in units.

In 2010, we granted 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 2010. All of these units 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 2009 and were settled in cash.

The DERs are paid in cash quarterly in arrears.

The following table presents information related to the Phantom Units:

	Units			Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2009		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		—		$	—
Granted		4,000		$	41.80
Vested		(4,000	)	$	41.80
Outstanding at December 31, 2011		—		$	—	$	—

45

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to Phantom Units:

	Year Ended December 31,
	2011(a)		2010		2009
	(Millions)
Fair value of units vested	$	0.2	$	0.2	$	0.5
Unit-based liabilities paid	$	—	$	—	$	0.5

(a) We issued 4,000 units in September 2011 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. Of the remaining RPUs outstanding at December 31, 2011, 6,125 units are expected to vest on December 31, 2012 and 8,215 units are expected to vest on December 31, 2013. The DERs are paid in cash quarterly in arrears.

At December 31, 2011, there was approximately $0.2 million of unrecognized compensation expense related to the RPUs that is expected to be recognized over a weighted-average period of 1 year. The following table presents information related to the RPUs:

	Units			Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2009		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
Granted		10,580		$	41.80
Vested		(58,600	)	$	12.97
Forfeited		—		$	—
Outstanding at December 31, 2011		19,330		$	37.27	$	47.47
Expected to vest		14,340		$	37.53	$	47.47

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:

	Year Ended December 31,
	2011 (a)		2010
	(Millions)
Fair value of units vested	$	2.5	$	0.5
Unit-based liabilities paid	$	0.6	$	—

(a) $0.6 million of the liabilities paid in 2011 relate to the 14,215 units and DERs that vested in 2010.

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 22% for units granted in 2011, 30% for units granted in 2010 and 21% for units granted in 2009. 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.

46

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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 balance as of December 31, 2011 and no federal income tax expense for the year ended December 31, 2010. On December 30, 2010, we acquired all of the interests in Marysville Hydrocarbons Holdings, LLC, an entity that owned a taxable C-Corporation consolidated return group. We estimated $35.0 million of deferred tax liabilities resulting from built-in tax gains recognized in the transaction and 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 triggered the deferred tax liabilities resulting from built-in tax gains to become currently payable. Accordingly, the estimated $35.0 million of deferred tax liabilities at December 31, 2010 became currently payable on January 4, 2011. During 2011, we made federal and state tax payments of $29.3 million and $0.3 million, respectively, related to our estimated $35.0 million tax liability that resulted from our acquisition of Marysville. The remaining $5.4 million estimated tax payable has been reclassified to goodwill in our final accounting for the Marysville business combination.

The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned to Texas. During 2010 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 consists of the following:

	Year Ended December 31,
	2011			2010			2009
	(Millions)
Current:
Federal income tax expense	$	(29.3	)	$	—		$	—
State income tax expense		(1.3	)		(1.1	)		(1.0	)
Deferred:
Federal income tax benefit (expense)		29.3			—			—
State income tax benefit (expense)		0.8			(0.4	)		—
Total income tax expense	$	(0.5	)	$	(1.5	)	$	(1.0	)

We had net long-term deferred tax liabilities of $3.4 million and $4.1 million as of December 31, 2011 and 2010, 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 to 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. 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 allocating Available Cash generated during the 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 our Available Cash it will have the impact of reducing net income per LPU.

47

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Basic and diluted net income or loss per LPU is calculated by dividing limited partners’ interest in net income or loss, by the weighted-average number of outstanding LPUs during the period. Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding performance units, phantom units and restricted units. The dilutive effect of unit-based awards was 64,286 equivalent units during the year ended December 31, 2011. There were no dilutive unit-based awards during the year ended December 31, 2010.

17. Commitments and Contingent Liabilities

Litigation

Prospect — During the fourth quarter of 2011, we received a claim for arbitration (the “Claim”) filed with the American Arbitration Association by Prospect Street Energy, LLC and Prospect Street Ventures I, LLC (together, the “Claimants”) against EE Group, LLC (“EE Group”) and a number of other parties that previously owned, directly or indirectly, our Marysville NGL storage facility (collectively, the “Respondents”). EE Group is our indirect subsidiary which we acquired in connection with our acquisition of Marysville Hydrocarbons Holdings, LLC (“MHH”) on December 30, 2010 (the “Acquisition”). The Claim involves actions taken and time periods prior to our ownership of EE Group and MHH, and includes several causes of action including claims of civil conspiracy, breach of fiduciary duty and fraud. We acquired a 90% interest in MHH from Dart Energy Corporation (“Dart”), a 5% interest in MHH from Prospect Street Energy, LLC and a 100% interest in EE Group, which owned the remaining 5% interest in MHH. The Claim seeks, from the Respondents collectively, alleged actual, punitive and treble damages and disgorgement of profits, as well as fees and costs. The purchase agreements for the Acquisition contain indemnification and other provisions that may provide some protection to us for any breach of the representations, warranties and covenants made by the sellers in the Acquisition. At this point, we cannot predict whether we will have any liability for the Claim. This proceeding is subject to the uncertainties inherent in any litigation, and the ultimate outcome of this matter may not be known for an extended period of time. We intend to vigorously defend this matter.

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 2011 for the 2011-2012 insurance year. We contract with third party and affiliate insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay in the 2011-2012 insurance year compared with the 2010-2011 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 2011-2012 insurance year includes general and excess liability, onshore property damage, including named windstorm and business interruption, and offshore non-wind property and business interruption insurance. The availability of offshore named windstorm property and business interruption insurance has been significantly reduced over the past few years as a result of higher industry-wide damage claims. Additionally, the named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, higher deductibles and lower coverage limits. As such, Discovery has elected to not purchase offshore named windstorm property and business interruption insurance coverage for the 2011-2012 insurance year.

48

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

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.

During the first quarter of 2011, we discovered excess emissions at our East Texas gas plant. We met with the Texas Commission on Environmental Quality, or TCEQ, in April 2011 to discuss this matter and included these issues in Title V reports we submitted to the State. In August 2011, the TCEQ conducted a standard inspection at the East Texas gas plant to evaluate compliance with applicable air quality requirements. On August 31, 2011, the TCEQ issued us a Notice of Violation and a Notice of Enforcement citing a number of alleged violations of terms and requirements of the facility air permit. We responded to the Notice of Violation on September 28, 2011, including the implemented measures to ensure the facility is in compliance with the relevant air permit terms and conditions. We responded to the Notice of Enforcement on October 14, 2011, including a description of the measures that have been implemented, and will be implemented at the facility to ensure compliance with the relevant air permit terms and conditions. In December we received a proposed penalty assessment for this matter and we believe that we will likely receive a penalty of up to $0.7 million for this matter. We do not believe the ultimate resolution of this matter will 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.

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 $13.1 million, $12.8 million and $12.1 million for the years ended December 31, 2011, 2010 and 2009, 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, 2011:

	(Millions)
2012	$	12.5
2013		9.3
2014		4.3
2015		2.2
2016		1.1
Thereafter		1.0
Total minimum rental payments	$	30.4

49

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

18. Business Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) NGL Logistics; and (3) Wholesale Propane Logistics.

Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing, treating, processing, transporting and storing natural gas. The segment consists of our Northern Louisiana system, our Southern Oklahoma system, our Wyoming system, our Michigan system, our Southeast Texas system, our 50.1% interest in the East Texas system, our 75% interest in the Colorado system, and our 40% limited liability company interest in Discovery.

NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of the Seabreeze and Wilbreeze intrastate NGL pipelines, the Wattenberg and Black Lake interstate NGL pipelines, the NGL storage facility in Michigan and the DJ Basin NGL Fractionators in Colorado.

Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of propane by pipeline, rail or ship to our terminals that deliver the product to retail distributors. The segment consists of six owned rail terminals, one owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

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.

50

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

The following tables set forth our segment information:

Year Ended December 31, 2011:

	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Eliminations (f)			Total
	(Millions)
Total operating revenue	$	1,670.4		$	56.6		$	633.6		$	—		$	(2.2	)	$	2,358.4
Gross margin (a)	$	322.3		$	52.0		$	51.1		$	—		$	—		$	425.4
Operating and maintenance expense		(94.7	)		(15.9	)		(15.1	)		—			—			(125.7	)
Depreciation and amortization expense		(89.5	)		(8.2	)		(2.9	)		—			—			(100.6	)
General and administrative expense		—			—			—			(48.3	)		—			(48.3	)
Earnings from unconsolidated affiliates		22.7			—			—			—			—			22.7
Other operating income		—			0.5			—			—			—			0.5
Interest expense		—			—			—			(33.9	)		—			(33.9	)
Income tax expense (b)		—			—			—			(0.5	)		—			(0.5	)
Net income (loss)		160.8			28.4			33.1			(82.7	)		—			139.6
Net income attributable to noncontrolling interests		(18.8	)		—			—			—			—			(18.8	)
Net income (loss) attributable to partners	$	142.0		$	28.4		$	33.1		$	(82.7	)	$	—		$	120.8
Non-cash derivative mark-to-market (c)	$	41.8		$	—		$	0.3		$	(2.2	)	$	—		$	39.9
Capital expenditures	$	151.8		$	9.3		$	4.6		$	—		$	—		$	165.7
Acquisitions net of cash acquired	$	145.2		$	29.6		$	—		$	—		$	—		$	174.8
Investments in unconsolidated affiliates	$	7.0		$	—		$	—		$	—		$	—		$	7.0

Year Ended December 31, 2010:

	Natural  Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	1,617.6		$	17.6		$	473.2		$	—		$	2,108.4
Gross margin (a)	$	283.5		$	12.9		$	28.9		$	—		$	325.3
Operating and maintenance expense		(82.0	)		(3.7	)		(12.6	)		—			(98.3	)
Depreciation and amortization expense		(83.5	)		(2.6	)		(1.9	)		(0.1	)		(88.1	)
General and administrative expense		—			—			—			(45.8	)		(45.8	)
Earnings from unconsolidated affiliates		23.0			0.8			—			—			23.8
Other operating income		2.0			—			3.0			—			5.0
Step acquisition – equity interest re-measurement gain		—			9.1			—			—			9.1
Interest expense		—			—			—			(29.1	)		(29.1	)
Income tax expense (b)		—			—			—			(1.5	)		(1.5	)
Net income (loss)		143.0			16.5			17.4			(76.5	)		100.4
Net income attributable to noncontrolling interests		(9.2	)		—			—			—			(9.2	)
Net income (loss) attributable to partners	$	133.8		$	16.5		$	17.4		$	(76.5	)	$	91.2
Non-cash derivative mark-to-market (c)	$	(8.8	)	$	—		$	(1.0	)	$	1.4		$	(8.4	)
Capital expenditures	$	63.8		$	11.5		$	0.6		$	—		$	75.9
Acquisitions net of cash acquired	$	78.8		$	135.5		$	67.8		$	—		$	282.1
Investments in unconsolidated affiliates	$	2.3		$	—		$	—		$	—		$	2.3

51

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

Year Ended December 31, 2009:

	Natural  Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	1,119.2		$	10.5		$	348.2		$	—		$	1,477.9
Gross margin (a)	$	173.1		$	7.6		$	48.9		$	—		$	229.6
Operating and maintenance expense		(72.7	)		(1.2	)		(10.3	)		—			(84.2	)
Depreciation and amortization expense		(73.9	)		(1.4	)		(1.4	)		(0.2	)		(76.9	)
General and administrative expense		—			—			—			(43.1	)		(43.1	)
Earnings from unconsolidated affiliates		16.6			1.9			—			—			18.5
Other operating expense		(0.5	)		—			—			—			(0.5	)
Interest income		—			—			—			0.3			0.3
Interest expense		—			—			—			(28.3	)		(28.3	)
Income tax expense (b)		—			—			—			(1.0	)		(1.0	)
Net income (loss)		42.6			6.9			37.2			(72.3	)		14.4
Net income attributable to noncontrolling interests		(8.3	)		—			—			—			(8.3	)
Net income (loss) attributable to partners	$	34.3		$	6.9		$	37.2		$	(72.3	)	$	6.1
Non-cash derivative mark-to-market (c)	$	(84.2	)	$	—		$	0.8		$	(0.4	)	$	(83.8	)
Capital expenditures	$	181.7		$	—		$	0.5		$	—		$	182.2
Acquisitions net of cash acquired	$	44.5		$	—		$	—		$	—		$	44.5
Investments in unconsolidated affiliates	$	7.0		$	—		$	—		$	—		$	7.0

	December 31,
	2011		2010		2009
	(Millions)
Segment long-term assets:
Natural Gas Services	$	1,555.4	$	1,469.3	$	1,415.6
NGL Logistics (d)		250.1		221.7		32.3
Wholesale Propane Logistics (d)		104.2		101.7		53.2
Other (e)		14.0		4.1		13.1
Total long-term assets		1,923.7		1,796.8		1,514.2
Current assets		353.7		350.4		291.4
Total assets	$	2,277.4	$	2,147.2	$	1,805.6

(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane, NGLs and condensate. 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 relates primarily to the Texas margin tax and the Michigan business tax.

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

52

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

(d) 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.

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.

(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.

(f) Represents intersegment revenues consisting of sales of NGLs by Marysville in our NGL Logistics business to our Wholesale Propane business.

19. Supplemental Cash Flow Information

	Year Ended December 31,
	2011			2010		2009
	(Millions)
Cash paid for interest and income taxes:
Cash paid for interest, net of amounts capitalized	$	17.2		$	7.8	$	9.0
Cash paid for income taxes, net of income tax refunds	$	29.9		$	0.9	$	2.2
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	14.2		$	6.3	$	4.1
Other non-cash additions of property, plant and equipment	$	3.0		$	12.1	$	1.6
Accounts payable related to equity issuance costs	$	(0.2	)	$	0.2	$	—
Acquisition related contingent consideration	$	—		$	3.1	$	—
Non-cash contribution from noncontrolling interests	$	—		$	0.5	$	—
Net change in parent advances	$	4.4		$	—	$	—

20. Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2011 and 2010 were as follows (millions, except per unit amounts):

2011	First			Second			Third		Fourth			Year Ended December 31, 2011
Total operating revenues	$	633.9		$	575.6		$	593.6	$	555.3		$	2,358.4
Operating income	$	7.3		$	60.3		$	70.2	$	13.5		$	151.3
Net income	$	3.5		$	57.4		$	68.1	$	10.6		$	139.6
Net income attributable to noncontrolling interests	$	(3.5	)	$	(9.7	)	$	0.4	$	(6.0	)	$	(18.8	)
Net income attributable to partners	$	—		$	47.7		$	68.5	$	4.6		$	120.8
Limited partners’ interest in net (loss) income	$	(11.4	)	$	35.3		$	59.5	$	(8.2	)	$	75.2
Basic net (loss) income per limited partner unit	$	(0.28	)	$	0.80		$	1.35	$	(0.19	)	$	1.73

53

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

2010	First			Second			Third			Fourth			Year Ended December 31, 2010
Total operating revenues	$	644.8		$	438.1		$	447.1		$	578.4		$	2,108.4
Operating income	$	45.4		$	22.8		$	19.6		$	19.4		$	107.2
Net income	$	45.5		$	22.0		$	15.9		$	17.0		$	100.4
Net income attributable to noncontrolling interests	$	(0.1	)	$	(1.0	)	$	(3.3	)	$	(4.8	)	$	(9.2	)
Net income attributable to partners	$	45.4		$	21.0		$	12.6		$	12.2		$	91.2
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

21. Supplementary Information — Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream Partners, LP’s results on a consolidated basis. In conjunction with the universal shelf registration statement on Form S-3 filed with the SEC on May 26, 2010, the parent guarantor has agreed to fully and unconditionally guarantee securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

54

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Balance Sheets December 31, 2011 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	3.6		$	6.4		$	(2.4	)	$	7.6
Accounts receivable		—		—			214.8			—			214.8
Inventories		—		—			87.9			—			87.9
Other		—		—			43.4			—			43.4
Total current assets		—		3.6			352.5			(2.4	)		353.7
Property, plant and equipment, net		—		—			1,499.4			—			1,499.4
Goodwill and intangible assets, net		—		—			299.1			—			299.1
Advances receivable — consolidated subsidiaries		370.7		597.2			—			(967.9	)		—
Investments in consolidated subsidiaries		515.2		679.3			—			(1,194.5	)		—
Investments in unconsolidated affiliates		—		—			107.1			—			107.1
Other long-term assets		—		5.6			12.5			—			18.1
Total assets	$	885.9	$	1,285.7		$	2,270.6		$	(2,164.8	)	$	2,277.4
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	18.7		$	364.2		$	(2.4	)	$	380.5
Advances payable — consolidated subsidiaries		—		—			967.9			(967.9	)		—
Long-term debt		—		746.8			—			—			746.8
Other long-term liabilities		—		5.0			46.8			—			51.8
Total liabilities		—		770.5			1,378.9			(970.3	)		1,179.1
Commitments and contingent liabilities
Equity:
Partners’ equity
Predecessor equity		—		—			257.4			—			257.4
Net equity		885.9		534.6			423.7			(1,194.5	)		649.7
Accumulated other comprehensive loss		—		(19.4	)		(1.8	)		—			(21.2	)
Total partners’ equity		885.9		515.2			679.3			(1,194.5	)		885.9
Noncontrolling interests		—		—			212.4			—			212.4
Total equity		885.9		515.2			891.7			(1,194.5	)		1,098.3
Total liabilities and equity	$	885.9	$	1,285.7		$	2,270.6		$	(2,164.8	)	$	2,277.4

(a) The financial information as of December 31, 2011 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

55

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Balance Sheets December 31, 2010 (a)
	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		—		—			247.3			—			247.3
Inventories		—		—			73.6			—			73.6
Other		—		—			22.8			—			22.8
Total current assets		—		1.5			350.4			(1.5	)		350.4
Property, plant and equipment, net		—		—			1,378.6			—			1,378.6
Goodwill and intangible assets, net		—		—			304.2			—			304.2
Advances receivable — consolidated subsidiaries		333.4		534.7			—			(868.1	)		—
Investments in consolidated subsidiaries		522.7		661.4			—			(1,184.1	)		—
Investments in unconsolidated affiliates		—		—			104.3			—			104.3
Other long-term assets		—		2.3			7.4			—			9.7
Total assets	$	856.1	$	1,199.9		$	2,144.9		$	(2,053.7	)	$	2,147.2
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	0.2	$	19.5		$	297.1		$	(1.5	)	$	315.3
Advances payable — consolidated subsidiaries		—		—			868.1			(868.1	)		—
Long-term debt		—		647.8			—			—			647.8
Other long-term liabilities		—		9.9			98.2			—			108.1
Total liabilities		0.2		677.2			1,263.4			(869.6	)		1,071.2
Commitments and contingent liabilities
Equity:
Partners’ equity
Predecessor equity		—		—			337.8			—			337.8
Net equity		855.9		550.1			323.9			(1,184.1	)		545.8
Accumulated other comprehensive loss		—		(27.4	)		(0.3	)		—			(27.7	)
Total partners’ equity		855.9		522.7			661.4			(1,184.1	)		855.9
Noncontrolling interests		—		—			220.1			—			220.1
Total equity		855.9		522.7			881.5			(1,184.1	)		1,076.0
Total liabilities and equity	$	856.1	$	1,199.9		$	2,144.9		$	(2,053.7	)	$	2,147.2

(a) The financial information as of December 31, 2010 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

56

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Statements of Operations Year Ended December 31, 2011 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,178.5		$	—		$	2,178.5
Transportation, processing and other		—		—			172.2			—			172.2
Gains from commodity derivative activity, net		—		—			7.7			—			7.7
Total operating revenues		—		—			2,358.4			—			2,358.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			1,933.0			—			1,933.0
Operating and maintenance expense		—		—			125.7			—			125.7
Depreciation and amortization expense		—		—			100.6			—			100.6
General and administrative expense		—		—			48.3			—			48.3
Other, net		—		—			(0.5	)		—			(0.5	)
Total operating costs and expenses		—		—			2,207.1			—			2,207.1
Operating income		—		—			151.3			—			151.3
Interest expense, net		—		(33.5	)		(0.4	)		—			(33.9	)
Earnings from unconsolidated affiliates		—		—			22.7			—			22.7
Earnings from consolidated subsidiaries		120.8		154.3			—			(275.1	)		—
Income before income taxes		120.8		120.8			173.6			(275.1	)		140.1
Income tax expense		—		—			(0.5	)		—			(0.5	)
Net income		120.8		120.8			173.1			(275.1	)		139.6
Net income attributable to noncontrolling interests		—		—			(18.8	)		—			(18.8	)
Net income attributable to partners	$	120.8	$	120.8		$	154.3		$	(275.1	)	$	120.8

(a) The financial information as of December 31, 2011 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

57

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Statements of Operations Year Ended December 31, 2010 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	1,975.1		$	—		$	1,975.1
Transportation, processing and other		—		—			130.3			—			130.3
Gains from commodity derivative activity, net		—		—			3.0			—			3.0
Total operating revenues		—		—			2,108.4			—			2,108.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			1,783.1			—			1,783.1
Operating and maintenance expense		—		—			98.3			—			98.3
Depreciation and amortization expense		—		—			88.1			—			88.1
General and administrative expense		—		0.2			45.6			—			45.8
Step acquisition — equity interest re-measurement gain		—		—			(9.1	)		—			(9.1	)
Other, net		—		—			(5.0	)		—			(5.0	)
Total operating costs and expenses		—		0.2			2,001.0			—			2,001.2
Operating (loss) income		—		(0.2	)		107.4			—			107.2
Interest expense, net		—		(28.8	)		(0.3	)		—			(29.1	)
Earnings from unconsolidated affiliates		—		—			23.8			—			23.8
Earnings from consolidated subsidiaries		91.2		120.2			—			(211.4	)		—
Income before income taxes		91.2		91.2			130.9			(211.4	)		101.9
Income tax expense		—		—			(1.5	)		—			(1.5	)
Net income		91.2		91.2			129.4			(211.4	)		100.4
Net income attributable to noncontrolling interests		—		—			(9.2	)		—			(9.2	)
Net income attributable to partners	$	91.2	$	91.2		$	120.2		$	(211.4	)	$	91.2

(a) The financial information as of December 31, 2010 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

58

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Statements of Operations Year Ended December 31, 2009 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	1,429.3		$	—		$	1,429.3
Transportation, processing and other		—		—			104.9			—			104.9
Losses from commodity derivative activity, net		—		—			(56.3	)		—			(56.3	)
Total operating revenues		—		—			1,477.9			—			1,477.9
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			1,248.3			—			1,248.3
Operating and maintenance expense		—		—			84.2			—			84.2
Depreciation and amortization expense		—		—			76.9			—			76.9
General and administrative expense		—		0.1			43.0			—			43.1
Other, net		—		—			0.5			—			0.5
Total operating costs and expenses		—		0.1			1,452.9			—			1,453.0
Operating (loss) income		—		(0.1	)		25.0			—			24.9
Interest expense, net		—		(27.8	)		(0.2	)		—			(28.0	)
Earnings from unconsolidated affiliates		—		—			18.5			—			18.5
Earnings from consolidated subsidiaries		6.1		34.0			—			(40.1	)		—
Income before income taxes		6.1		6.1			43.3			(40.1	)		15.4
Income tax expense		—		—			(1.0	)		—			(1.0	)
Net income		6.1		6.1			42.3			(40.1	)		14.4
Net income attributable to noncontrolling interests		—		—			(8.3	)		—			(8.3	)
Net income attributable to partners	$	6.1	$	6.1		$	34.0		$	(40.1	)	$	6.1

(a) The financial information as of December 31, 2009 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

59

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2011 (a)
	Parent Guarantor			Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	(37.3	)	$	(92.7	)	$	391.7		$	(0.9	)	$	260.8
INVESTING ACTIVITIES:
Capital expenditures		—			—			(165.7	)		—			(165.7	)
Acquisitions, net of cash acquired		—			—			(174.8	)		—			(174.8	)
Investments in unconsolidated affiliates		—			—			(7.0	)		—			(7.0	)
Return of investment from unconsolidated affiliate		—			—			1.6			—			1.6
Proceeds from sale of assets		—			—			5.2			—			5.2
Net cash used in investing activities		—			—			(340.7	)		—			(340.7	)
FINANCING ACTIVITIES:
Proceeds from debt		—			1,524.0			—			—			1,524.0
Payments of debt		—			(1,425.0	)		—			—			(1,425.0	)
Payment of deferred financing costs		—			(4.2	)		—			—			(4.2	)
Proceeds from issuance of common units, net of offering costs		169.7			—			—			—			169.7
Excess purchase price over acquired assets		—			—			(35.7	)		—			(35.7	)
Net change in advances to predecessor from DCP Midstream LLC		—			—			10.9			—			10.9
Distributions to unitholders and general partner		(132.4	)		—			—			—			(132.4	)
Distributions to noncontrolling interests		—			—			(44.8	)		—			(44.8	)
Contributions from noncontrolling interests		—			—			18.3			—			18.3
Net cash provided by (used in) financing activities		37.3			94.8			(51.3	)		—			80.8
Net change in cash and cash equivalents		—			2.1			(0.3	)		(0.9	)		0.9
Cash and cash equivalents, beginning of period		—			1.5			6.7			(1.5	)		6.7
Cash and cash equivalents, end of period	$	—		$	3.6		$	6.4		$	(2.4	)	$	7.6

(a) The financial information as of December 31, 2011 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

60

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

	Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2010 (a)
	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	)	$	293.4		$	(0.7	)	$	162.4
INVESTING ACTIVITIES:
Capital expenditures		—			—			(75.9	)		—			(75.9	)
Acquisitions, net of cash acquired		—			—			(282.1	)		—			(282.1	)
Investments in unconsolidated affiliates		—			—			(2.3	)		—			(2.3	)
Return of investment from unconsolidated affiliate		—			—			1.2			—			1.2
Proceeds from sale of assets		—			—			3.5			—			3.5
Proceeds from sales of available-for-sale securities		—			10.1			—			—			10.1
Net cash provided by (used in) investing activities		—			10.1			(355.6	)		—			(345.5	)
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
Net change in advances to predecessor from DCP Midstream, LLC		—			—			82.3			—			82.3
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
Purchase of additional interest in a subsidiary		—			—			(3.5	)		—			(3.5	)
Net cash provided by (used in) financing activities		87.4			32.7			67.6			—			187.7
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

(a) The financial information as of December 31, 2010 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

61

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (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	)	$	168.9		$	(0.5	)	$	152.7
INVESTING ACTIVITIES:
Capital expenditures		—			—			(182.2	)		—			(182.2	)
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		—			—			1.4			—			1.4
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			(230.1	)		—			(180.1	)
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		—			—			(25.5	)		—			(25.5	)
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	)		26.9			—			(32.4	)
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

(a) The financial information as of December 31, 2009 includes the results of our 100% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

22. Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2011, 2010 and 2009 are as 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, 2011
Allowance for doubtful accounts	$	0.5	$	—	$	—	$	(0.2	)	$	0.3
Environmental		1.9		0.4		—		(0.3	)		2.0
Litigation		0.2		0.1		—		(0.3	)		—
Other (a)		—		0.5		—		—			0.5
	$	2.6	$	1.0	$	—	$	(0.8	)	$	2.8
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

(a) Principally consists of reserves against other long-term assets, which are included in other long-term assets, and 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 3, 2012, we entered into a 2-year Term Loan Agreement with Wells Fargo Bank, National Association, SunTrust Bank and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as lenders. We borrowed $135.0 million under the term loan on January 3, 2012, which was used to fund the acquisition of the remaining 49.9% interest in East Texas.

On January 3, 2012, we completed the acquisition of the remaining 49.9% interest in East Texas from DCP Midstream, LLC for aggregate consideration of $165.0 million, subject to certain working capital and other customary purchase price adjustments. The transaction was financed at closing through the execution of a term loan and the issuance of 727,520 common units. Prior to the contribution of the additional interest in East Texas, we owned a 50.1% interest which we accounted for as a consolidated subsidiary. The contribution of the remaining 49.9% interest in East Texas represents a transaction between entities under common control, but does not represent a change in reporting entity. Accordingly, we will include the results of the remaining 49.9% interest in East Texas prospectively from the date of contribution.

63

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2011, 2010 and 2009 — (Continued)

On January 18, 2012, we, along with Williams Partners L.P., announced a planned expansion of the Discovery natural gas gathering pipeline system in the deepwater Gulf of Mexico. Discovery intends to construct the Keathley Canyon Connector, a 20-inch diameter, 215-mile subsea natural gas gathering pipeline for production from the Keathley Canyon, Walker Ridge and Green Canyon areas in the central deepwater Gulf of Mexico. The Keathley Canyon Connector will originate in the southeast portion of the Keathley Canyon area and terminate into Discovery’s 30-inch diameter mainline near South Timbalier Block 283. The pipeline will be capable of gathering more than 400 MMcf/d of natural gas. Discovery has signed long-term fee-based agreements with the Lucius and Hadrian South owners for natural gas gathering and processing for production from those fields. Construction on the project is expected to begin in 2013, with a mid-2014 expected in-service date. Total capital expenditures for the Keathley Canyon Connector are estimated to be approximately $600.0 million, of which our portion is approximately $240.0 million.

On January 26, 2012, the board of directors of the general partner declared a quarterly distribution of $0.65 per unit, payable on February 14, 2012 to unitholders of record on February 7, 2012.

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative instruments related to the Southeast Texas storage business, for aggregate consideration of $240.0 million, subject to certain working capital and other customary purchase price adjustments. $192.0 million of the aggregate purchase price was financed with a portion of the net proceeds from our 4.95% 10-year Senior Notes offering. The remaining $48.0 million consideration was financed by the issuance at closing of an aggregate of 1,000,417 of our common units. DCP Midstream, LLC also provided fixed price NGL commodity derivatives, valued at $39.5 million, for the three year period subsequent to closing the newly acquired interest. Certain of the NGL commodity derivatives were valued at $24.6 million and represent consideration for the termination of a fee-based storage arrangement we had with DCP Midstream, LLC in conjunction with our initial 33.33% interest in Southeast Texas; the remaining portion of the commodity derivatives, valued at $14.9 million, mitigate a portion of our currently anticipated commodity price risk associated with the gathering and processing portion of the 66.67% interest in Southeast Texas acquired on March 30, 2012. The $29.6 million deficit purchase price under the historical basis of the net assets acquired and the $48.0 million of common units issued as consideration for this acquisition were recorded as an increase in common unitholders equity. Prior to the acquisition of the additional interest in Southeast Texas, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method. The acquisition of the remaining 66.67% interest in Southeast Texas represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated financial statements have been adjusted to retrospectively include the historical results of our 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business for all periods presented, similar to the pooling method.

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