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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. 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 $252,999,000 and $139,512,000 at December 31, 2012 and 2011, respectively, and in Discovery’s net income of $12,091,000, $20,323,000, and $20,750,000 for the years ended December 31, 2012, 2011, and 2010 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements give retrospective effect for the Company’s acquisition of 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.

The consolidated financial statements give retrospective effect for the Company’s acquisition of the 80% ownership in DCP SC Texas GP, of which 33.33% and 46.67% was acquired on November 7, 2012 and March 28, 2013, 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, 2012 attributable to DCP Southeast Texas Holdings, GP and DCP SC Texas GP has 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 and DCP SC Texas GP had been operated as unaffiliated entities. 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 new disclosure requirements regarding information related to balance sheet offsetting of assets and liabilities as disclosed in Note 11 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, 2012, 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 27, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting based on our audit.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 27, 2013 (June 14, 2013 as to Notes 1, 3, 11 and 22)

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2012			2011
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	8
Accounts receivable:
Trade, net of allowance for doubtful accounts of less than $1 million		107			125
Affiliates		132			107
Inventories		76			90
Unrealized gains on derivative instruments		49			41
Other		2			2
Total current assets		368			373
Property, plant and equipment, net		2,550			2,114
Goodwill		154			154
Intangible assets, net		137			145
Investments in unconsolidated affiliates		304			108
Unrealized gains on derivative instruments		70			7
Other long-term assets		20			11
Total assets	$	3,603		$	2,912
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	151		$	342
Affiliates		72			72
Unrealized losses on derivative instruments		31			60
Capital spending accrual		44			31
Other		47			37
Total current liabilities		345			542
Long-term debt		1,620			747
Unrealized losses on derivative instruments		8			33
Other long-term liabilities		36			28
Total liabilities		2,009			1,350
Commitments and contingent liabilities:
Equity:
Predecessor equity		357			628
Common unitholders (61,346,058 and 44,848,703 units issued and outstanding, respectively)		1,063			654
General partner		—			(5	)
Accumulated other comprehensive loss		(15	)		(21	)
Total partners’ equity		1,405			1,256
Noncontrolling interests		189			306
Total equity		1,594			1,562
Total liabilities and equity	$	3,603		$	2,912

See accompanying notes to consolidated financial statements.

2

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2012			2011			2010
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	820		$	1,171		$	1,185
Sales of natural gas, propane, NGLs and condensate to affiliates		1,639			2,316			1,853
Transportation, processing and other		179			169			136
Transportation, processing and other to affiliates		53			36			24
Gains from commodity derivative activity, net		17			7			5
Gains (losses) from commodity derivative activity, net — affiliates		53			1			(2	)
Total operating revenues		2,761			3,700			3,201
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,807			2,445			2,372
Purchases of natural gas, propane and NGLs from affiliates		370			655			386
Operating and maintenance expense		193			188			155
Depreciation and amortization expense		89			133			115
General and administrative expense		17			19			14
General and administrative expense — affiliates		57			56			52
Step acquisition — equity interest re-measurement gain		—			—			(9	)
Other income		—			(1	)		(2	)
Other income — affiliates		—			—			(3	)
Total operating costs and expenses		2,533			3,495			3,080
Operating income(loss)		228			205			121
Interest expense		(42	)		(34	)		(29	)
Earnings from unconsolidated affiliates		26			23			23
Income before income taxes		212			194			115
Income tax expense		(1	)		(1	)		(2	)
Net income		211			193			113
Net income attributable to noncontrolling interests		(13	)		(30	)		(12	)
Net income attributable to partners		198			163			101
Net income attributable to predecessor operations		(33	)		(63	)		(53	)
General partner’s interest in net income		(41	)		(25	)		(17	)
Net income allocable to limited partners	$	124		$	75		$	31
Net income per limited partner unit — basic	$	2.28		$	1.73		$	0.86
Net income per limited partner unit — diluted	$	2.28		$	1.72		$	0.86
Weighted-average limited partner units outstanding — basic		54.5			43.5			36.1
Weighted-average limited partner units outstanding — diluted		54.5			43.6			36.1

See accompanying notes to consolidated financial statements.

3

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2012			2011			2010
	(Millions)
Net income	$	211		$	193		$	113
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings		10			21			23
Net unrealized losses on cash flow hedges		—			(13	)		(19	)
Net unrealized losses on cash flow hedges – predecessor operations		(1	)		(2	)		—
Total other comprehensive income		9			6			4
Total comprehensive income		220			199			117
Total comprehensive income attributable to noncontrolling interests		(13	)		(30	)		(12	)
Total comprehensive income attributable to partners	$	207		$	169		$	105

See accompanying notes to consolidated financial statements.

4

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Partners’ Equity
	Predecessor Equity			Common Unitholders			General Partner			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2012	$	628		$	654		$	(5	)	$	(21	)	$	306		$	1,562
Net income		33			124			41			—			13			211
Other comprehensive income (loss)		(1	)		—			—			10			—			9
Net change in advances to predecessor from DCP Midstream, LLC		200			—			—			—			40			240
Acquisition of 33.33% interest in the Eagle Ford system		(232	)		—			—			—			—			(232	)
Acquisition of additional 66.67% interest in Southeast Texas and NGL Hedge		(248	)		40			—			—			—			(208	)
Acquisition of additional 49.9% interest in East Texas		—			—			—			—			(176	)		(176	)
Issuance of units for Southeast Texas		—			48			—			—			—			48
Issuance of units for East Texas		—			33			—			—			—			33
Issuance of units for Mont Belvieu fractionators		—			60			—			—			—			60
Issuance of units for 33.33% interest in the Eagle Ford system		—			88			—			—			—			88
Deficit purchase price under carrying value of acquired net assets for Southeast Texas and East Texas		—			36			—			(4	)		—			32
Excess purchase price over carrying value of acquired investments in Mont Belvieu fractionators		—			(175	)		—			—			—			(175	)
Excess purchase price over carrying value of acquired investment of 33.33% interest in the Eagle Ford system and NGL Hedge		—			(156	)		—			—			—			(156	)
Excess purchase price over carrying value of acquired net assets by the Eagle Ford system for Goliad and NGL Hedge		(23	)		(9	)		—			—			(10	)		(42	)
Issuance of 11,285,956 common units		—			455			—			—			—			455
Distributions to common unitholders and general partner		—			(145	)		(36	)		—			—			(181	)
Distributions to noncontrolling interests		—			—			—			—			(9	)		(9	)
Contributions from noncontrolling interests		—			—			—			—			25			25
Contributions from DCP Midstream, LLC		—			10			—			—			—			10
Balance, December 31, 2012	$	357		$	1,063		$	—		$	(15	)	$	189		$	1,594

See accompanying notes to consolidated financial statements.

5

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY —   (Continued)

	Partner’s Equity
	Predecessor Equity			Common Unitholders			General Partner			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2010	$	420		$	416		$	(6	)	$	(32	)	$	279		$	1,077
Net income		53			31			17			—			12			113
Other comprehensive income		—			—			—			4			—			4
Net change in advances to predecessor from DCP Midstream, LLC		137			—			—			—			14			151
Purchase of additional interest in a subsidiary		—			1			—			—			(5	)		(4	)
Issuance of 5,870,200 common units		—			189			—			—			—			189
Distributions to common unitholders and general partner		—			(85	)		(17	)		—			—			(102	)
Distributions to noncontrolling interests		—			—			—			—			(26	)		(26	)
Contributions from DCP Midstream, LLC		—			1			—			—			—			1
Contributions from noncontrolling interests		—			—			—			—			14			14
Excess purchase price over carrying value of acquired investment of 5% interest in Black Lake		—			(1	)		—			—			—			(1	)
Balance, December 31, 2010	$	610		$	552		$	(6	)	$	(28	)	$	288		$	1,416
Net income		63			75			25			—			30			193
Other comprehensive income (loss)		(2	)		—			—			8			—			6
Net change in advances to predecessor from DCP Midstream, LLC		71			—			—			—			15			86
Acquisition of Southeast Texas		(114	)		—			—			—			—			(114	)
Excess purchase price over acquired assets		—			(35	)		—			(1	)		—			(36	)
Issuance of 4,357,921 common units		—			170			—			—			—			170
Equity-based compensation		—			3			—			—			—			3
Distributions to DCP Midstream, LLC		—			(3	)		—			—			—			(3	)
Distributions to common unitholders and general partner		—			(108	)		(24	)		—			—			(132	)
Distributions to noncontrolling interests		—			—			—			—			(45	)		(45	)
Contributions from noncontrolling interests		—			—			—			—			18			18
Balance, December 31, 2011	$	628		$	654		$	(5	)	$	(21	)	$	306		$	1,562

See accompanying notes to consolidated financial statements.

6

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2012			2011			2010
	(Millions)
OPERATING ACTIVITIES:
Net income	$	211		$	193		$	113
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		89			133			115
Earnings from unconsolidated affiliates		(26	)		(23	)		(23	)
Distributions from unconsolidated affiliates		24			25			30
Step acquisition – equity interest re-measurement gain		—			—			(9	)
Net unrealized (gains) losses on derivative instruments		(21	)		(40	)		8
Deferred income taxes, net		—			(29	)		—
Other, net		3			5			(1	)
Change in operating assets and liabilities which (used) provided cash, net of effects of acquisitions:
Accounts receivable		(11	)		34			(52	)
Inventories		14			(14	)		1
Accounts payable		(194	)		106			16
Accrued interest		5			—			2
Other current assets and liabilities		(4	)		2			3
Other long-term assets and liabilities		(8	)		(5	)		2
Net cash provided by operating activities		82			387			205
INVESTING ACTIVITIES:
Capital expenditures		(483	)		(384	)		(185	)
Acquisitions, net of cash acquired		(433	)		(38	)		(282	)
Acquisition of unconsolidated affiliates and NGL Hedges		(312	)		(114	)		—
Investments in unconsolidated affiliates		(158	)		(8	)		(2	)
Return of investment from unconsolidated affiliates		1			2			1
Proceeds from sales of assets		2			5			4
Proceeds from sales of available-for-sale securities		—			—			10
Net cash used in investing activities		(1,383	)		(537	)		(454	)
FINANCING ACTIVITIES:
Proceeds from debt		2,665			1,524			868
Payments of debt		(1,792	)		(1,425	)		(835	)
Payment of deferred financing costs		(8	)		(4	)		(2	)
Proceeds from issuance of common units, net of offering costs		455			170			189
Excess purchase price over acquired assets		(225	)		(36	)		—
Net change in advances to predecessor from DCP Midstream, LLC		355			81			151
Distributions to common unitholders and general partner		(181	)		(132	)		(102	)
Distributions to noncontrolling interests		(9	)		(45	)		(26	)
Contributions from noncontrolling interests		25			18			14
Contributions from DCP Midstream, LLC		10			—			1
Purchase of additional interest in a subsidiary		—			—			(4	)
Net cash provided by financing activities		1,295			151			254
Net change in cash and cash equivalents		(6	)		1			5
Cash and cash equivalents, beginning of year		8			7			2
Cash and cash equivalents, end of year	$	2		$	8		$	7

See accompanying notes to consolidated financial statements.

7

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

1. Description of Business and Basis of Presentation

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

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 segment (which includes our Northern Louisiana system; our Southern Oklahoma system; our 40% 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; our East Texas system (of which the remaining 49.9% was acquired in January 2012, and also includes the Crossroads system acquired in July 2012); our Michigan system; our Southeast Texas system (of which 33.33% and 66.67% were acquired in January 2011 and March 2012, respectively); our 80% interest in DCP SC Texas GP, or the Eagle Ford system (of which 33.33% and 46.67% were acquired in November 2012 and March 2013, respectively), the Goliad plant, and our wholly owned Eagle Plant, our NGL logistics segment (which includes the Seabreeze and Wilbreeze intrastate NGL pipelines, the Wattenberg and Black Lake interstate NGL pipelines, our 10% interest in the Texas Express intrastate NGL pipeline, the NGL storage facility in Michigan, the DJ Basin NGL fractionators and our minority ownership interests in the Mont Belvieu fractionators acquired in July 2012), and our wholesale propane logistics segment.

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 Phillips 66. 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 28% of us.

The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. 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 initial 33.33% interest in Southeast Texas, which was acquired from DCP Midstream, LLC in January 2011, and the remaining 66.67% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business, which we acquired from DCP Midstream, LLC in March 2012, and an 80% interest in the Eagle Ford system, of which we acquired 33.33% and 46.67% in November 2012 and March 2013, respectively, from DCP Midstream, LLC. 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 the March 2012 transaction, we own 100% of Southeast Texas which we account for as a consolidated subsidiary. Prior to our acquisition of the additional 46.67% interest in the Eagle Ford system, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to the March 2013 transaction, we own 80% of the Eagle Ford system 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 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business, and 80% interest in the Eagle Ford system 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 in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction or an addition to limited 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. In addition, the results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates.

8

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

These consolidated financial statements include the accounts of the Eagle Ford system and, prior to November 2, 2012, the operations, assets and liabilities contributed to the Eagle Ford system by DCP Midstream, LLC in a drop-down transaction. Certain assets and liabilities presented with the December 31, 2011 balance sheet of the Eagle Ford system were excluded from the November 2, 2012 drop-down transaction, and as such are not included in the 2012 results of the Eagle Ford system. These excluded assets and liabilities are defined within the Contribution Agreement and include (1) property, plant and equipment of $171 million; (2) other long-term assets of $2 million; (3) accounts payable trade of $6 million; (4) accrued capital expenditures of $49 million; (5) accrued liabilities and other of $2 million and (6) other long-term liabilities of $1 million, and result in a net equity impact of $115 million.

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.

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, terminal year multiples, and estimated future cash flows including 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

• 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.

9

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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.

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 purchase 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:

10

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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.

11

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Revenue Recognition — We generate the majority of our revenues from gathering, compressing, treating, processing, transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. 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, transporting or storing 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 propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their 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.

12

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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 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, 2012, 2011 and 2010. There was one third party customer that accounted for approximately 20% of revenues of the Wholesale Propane Logistics segment for the year ended December 31, 2012, and approximately 17% of total operating revenues for the years ended December 31, 2011 and 2010, respectively. 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, 2012 and 2011, included in the consolidated balance sheets as other current liabilities amounted to $1 million and $1 million, respectively, and as other long-term liabilities amounted to $1 million and $2 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 net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss 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.

Capitalized Interest — We capitalize interest during construction on major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.

13

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

3. Acquisitions

On November 2, 2012, we acquired a 33.33% interest in the Eagle Ford system from DCP Midstream, LLC and a $43 million fixed price commodity derivative hedge (referred to as the NGL Hedge) for a three-year period for aggregate consideration of $438 million, less customary working capital and other purchase price adjustments of $7 million. $343 million of the consideration was financed with a 2-year Term Loan Agreement and $88 million was financed by the issuance at closing of an aggregate 1,912,663 of our common units to DCP Midstream, LLC. The $156 million excess purchase price over the carrying value of the acquired investment was recorded as a decrease in common unitholders’ equity.

On March 28, 2013, we acquired an additional 46.67% interest the Eagle Ford system from DCP Midstream, LLC and an $87 million fixed price commodity derivative hedge for a three-year period for aggregate consideration of $626 million, plus customary working capital and other purchase price adjustments. $490 million of the consideration was financed with the net proceeds from our 3.875% 10-year Senior Notes offering, $125 million was financed by the issuance at closing of an aggregate 2,789,739 of our common units to DCP Midstream, LLC and the remaining $11 million was paid with cash on hand.

On December 5, 2012, the Eagle Ford system announced the construction of the Goliad plant, a cryogenic plant that will serve the Eagle Ford shale. The Goliad plant will have gas processing capacity of 200 MMcf/d and will be part of the Eagle Ford system. The Eagle Ford system acquired working capital and construction work in progress from DCP Midstream, LLC for $107 million. The purchase price comprised of a payment of $57 million for construction work in progress and working capital and a $50 million incremental payment for preformation capital expenditures . We contributed $19 million to the Eagle Ford system for our initial 33.33% interest in the project, plus an incremental payment of $17 million as reimbursement for 33.33% of preformation capital expenditures. DCP Midstream, LLC also provided an $8 million two-year direct commodity price hedge (also referred to as the NGL Hedge) for our 33.33% interest in the project. The excess purchase price over the carrying value of the acquired net assets by the Eagle Ford system of $9 million was recorded as a decrease in common unitholders’ equity. On March 28, 2013, we also reimbursed DCP Midstream, LLC $50 million for 46.67% of the capital spent to date by the Eagle Ford system for the construction of the Goliad plant, plus an incremental payment of $23 million as reimbursement for 46.67% of preformation capital expenditures. The excess purchase price over the carrying value of the additional acquired net assets by the Eagle Ford system of $23 million was recorded as a decrease in predecessor equity, and $10 million was recorded as a decrease in noncontrolling interests. The Goliad plant will be constructed and funded by the Eagle Ford system. Our total investment will be approximately $230 million, net of the noncontrolling interest portion of $60 million, which includes the new Goliad plant, a gathering system feeding the plant and ancillary support facilities including compression, liquids handling and residue pipeline interconnect facilities. The Goliad plant is expected to be completed in the first quarter of 2014.

Prior to the acquisition of the additional interest in the Eagle Ford system, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method of accounting. The acquisition of the additional interest in the Eagle Ford system 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 80% interest in the Eagle Ford system for all periods presented, similar to the pooling method. Our interest in the Eagle Ford system is included in our Natural Gas Services segment.

14

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas and commodity derivative hedge instruments (also referred to as the NGL Hedge) related to the Southeast Texas storage business for consideration of $240 million, subject to working capital and other customary purchase price adjustments. $192 million of the consideration was financed with a portion of the net proceeds from our 4.95% 10-year Senior Notes offering. The remaining $48 million consideration was financed by the issuance at closing of an aggregate of 1,000,417 of our common units to DCP Midstream, LLC. DCP Midstream, LLC also provided fixed price NGL commodity derivatives, valued at $40 million, for the three year period subsequent to closing the newly acquired interest. The $9 million deficit purchase price under the carrying value of the acquired net assets and the $48 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. Certain of the NGL commodity derivatives were valued at $25 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 $15 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 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 commodity derivative hedge instruments associated with the storage business for all periods presented, similar to the pooling method.

    Historical Financial Information

The results of our 80% interest in the Eagle Ford system are included in the consolidated balance sheet as of December 31, 2012. The following table presents the previously reported December 31, 2012 consolidated balance sheet, adjusted for the acquisition of the additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC:

15

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

As of December 31, 2012

	DCP Midstream Partners,  LP (As previously reported) (a)			Consolidate Eagle Ford system (b)		Remove Eagle Ford system Investment in Unconsolidated Affiliate (c)			Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1	$	—		$	2
Accounts receivable		182			57		—			239
Inventories		75			1		—			76
Other		51			—		—			51
Total current assets		309			59		—			368
Property, plant and equipment, net		1,727			823		—			2,550
Goodwill and intangible assets, net		291			—		—			291
Investments in unconsolidated affiliates		558			1		(255	)		304
Other non-current assets		87			3		—			90
Total assets	$	2,972		$	886	$	(255	)	$	3,603
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	234		$	111	$	—		$	345
Long-term debt		1,620			—		—			1,620
Other long-term liabilities		35			9		—			44
Total liabilities		1,889			120		—			2,009
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity		1,063			612		(255	)		1,420
Accumulated other comprehensive loss		(15	)		—		—			(15	)
Total partners’ equity		1,048			612		(255	)		1,405
Noncontrolling interests		35			154		—			189
Total equity		1,083			766		(255	)		1,594
Total liabilities and equity	$	2,972		$	886	$	(255	)	$	3,603

(a) Amounts as previously reported with 33.33% of the Eagle Ford system presented within investments in unconsolidated affiliates.

(b) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

(c) Adjustments to remove the Eagle Ford system 33.33% investment in unconsolidated affiliates.

16

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

The results of our 100% interest in Southeast Texas and our 80% interest in the Eagle Ford system are included in the consolidated balance sheet as of December 31, 2011. The following table presents the previously reported December 31, 2011 consolidated balance sheet, adjusted for the acquisitions of the remaining 66.67% interest in Southeast Texas and our 80% interest in the Eagle Ford system from DCP Midstream, LLC:

As of December 31, 2011

	DCP Midstream Partners,  LP (As reported on 2011 Form 10-K filed on 2/29/12) (a)			Consolidate Southeast Texas system (b)			Remove Southeast Texas Investment in Unconsolidated Affiliate (c)			DCP Midstream Partners,  LP (As reported on Form 8-K filed on 6/14/12)			Consolidate Eagle Ford system (d)		Consolidated DCP Midstream Partners, LP (As currently reported)
											(Millions	)
ASSETS
Current assets:
Cash and cash equivalents	$	7		$	1		$	—		$	8		$	—	$	8
Accounts receivable		161			54			—			215			17		232
Inventories		65			23			—			88			2		90
Other		7			36			—			43			—		43
Total current assets		240			114			—			354			19		373
Property, plant and equipment, net		1,182			317			—			1,499			615		2,114
Goodwill and intangible assets, net		256			43			—			299			—		299
Investments in unconsolidated affiliates		209			—			(102	)		107			1		108
Other non-current assets		17			1			—			18			—		18
Total assets	$	1,904		$	475		$	(102	)	$	2,277		$	635	$	2,912
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	269		$	111		$	—		$	380		$	162	$	542
Long-term debt		747			—			—			747			—		747
Other long-term liabilities		47			5			—			52			9		61
Total liabilities		1,063			116			—			1,179			171		1,350
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity		650			361			(104	)		907			370		1,277
Accumulated other comprehensive loss		(21	)		(2	)		2			(21	)		—		(21	)
Total partners’ equity		629			359			(102	)		886			370		1,256
Noncontrolling interests		212			—			—			212			94		306
Total equity		841			359			(102	)		1,098			464		1,562
Total liabilities and equity	$	1,904		$	475		$	(102	)	$	2,277		$	635	$	2,912

(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 the Southeast Texas 33.33% investment in unconsolidated affiliates.

(d) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

17

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

The results of our 80% interest in the Eagle Ford system are included in the consolidated statements of operations for the year ended December 31, 2012. The following table presents the previously reported consolidated statements of operations for the year ended December 31, 2012 adjusted for the acquisition of the additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC:

Year Ended December 31, 2012

	DCP Midstream Partners, LP (As previously reported) (a)			Consolidate Eagle Ford system (b)			Remove Eagle Ford system Equity Earnings (c)			Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	1,466		$	993		$	—		$	2,459
Transportation, processing and other		185			47			—			232
Losses from commodity derivative activity, net		70			—			—			70
Total operating revenues		1,721			1,040			—			2,761
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,301			876			—			2,177
Operating and maintenance expense		123			70			—			193
Depreciation and amortization expense		64			25			—			89
General and administrative expense		46			28			—			74
Total operating costs and expenses		1,534			999			—			2,533
Operating income		187			41			—			228
Interest expense, net		(42	)		—			—			(42	)
Earnings from unconsolidated affiliates		29			—			(3	)		26
Income before income taxes		174			41			(3	)		212
Income tax expense		(1	)		—			—			(1	)
Net income		173			41			(3	)		211
Net income attributable to noncontrolling interests		(5	)		(8	)		—			(13	)
Net income attributable to partners	$	168		$	33		$	(3	)	$	198

(a) Amounts as previously reported with 33.33% of the Eagle Ford system presented within earnings from unconsolidated affiliates.

(b) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

(c) Adjustments to remove the Eagle Ford system equity earnings at 33.33% from the date of acquisition through December 31, 2012.

18

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

The results of our 100% interest in Southeast Texas and our 80% interest in the Eagle Ford system are included in the consolidated statements of operations for the years ended December 31, 2011 and 2010. The following tables present the previously reported consolidated statements of operations for the years ended December 31, 2011 and 2010 adjusted for the acquisitions of the remaining 66.67% interest in Southeast Texas and our 80% interest in the Eagle Ford system from DCP Midstream, LLC:

Year Ended December 31, 2011

	DCP Midstream Partners,  LP (As reported on 2011 Form 10-K filed on 2/29/12) (a)			Consolidate Southeast Texas system (b)		Remove Southeast Texas Equity Earnings (c)			DCP Midstream Partners,  LP (As reported on Form 8-K filed on 6/14/12)			Consolidate Eagle Ford system (d)			Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Operating costs and expenses:
Sales of natural gas, propane, NGLs and condensate	$	1,413		$	765	$	—		$	2,178		$	1,309		$	3,487
Transportation, processing and other		163			9		—			172			33			205
(Losses) gains from commodity derivative activity, net		(6	)		14		—			8			—			8
Total operating revenues		1,570			788		—			2,358			1,342			3,700
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,230			703		—			1,933			1,167			3,100
Operating and maintenance expense		106			20		—			126			62			188
Depreciation and amortization expense		81			20		—			101			32			133
General and administrative expense		37			11		—			48			27			75
Other income		(1	)		—		—			(1	)		—			(1	)
Total operating costs and expenses		1,453			754		—			2,207			1,288			3,495
Operating income		117			34		—			151			54			205
Interest expense, net		(34	)		—		—			(34	)		—			(34	)
Earnings from unconsolidated affiliates		37			—		(14	)		23			—			23
Income before income taxes		120			34		(14	)		140			54			194
Income tax expense		—			—		—			—			(1	)		(1	)
Net income		120			34		(14	)		140			53			193
Net income attributable to noncontrolling interests		(19	)		—		—			(19	)		(11	)		(30	)
Net income attributable to partners	$	101		$	34	$	(14	)	$	121		$	42		$	163

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented within 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%.

(d) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

19

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Year Ended December 31, 2010

	DCP Midstream Partners,  LP (As reported on 2011 Form 10-K filed on 2/29/12) (a)			Consolidate Southeast Texas system (b)			Remove Southeast Texas Equity Earnings (c)			DCP Midstream Partners,  LP (As reported on Form 8-K filed on 6/14/12)			Consolidate Eagle Ford system (d)			Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Operating costs and expenses:
Sales of natural gas, propane, NGLs and condensate	$	1,163		$	812		$	—		$	1,975		$	1,063		$	3,038
Transportation, processing and other		115			15			—			130			30			160
(Losses) gains from commodity derivative activity, net		(9	)		12			—			3			—			3
Total operating revenues		1,269			839			—			2,108			1,093			3,201
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,032			751			—			1,783			975			2,758
Operating and maintenance expense		80			18			—			98			57			155
Depreciation and amortization expense		73			15			—			88			27			115
General and administrative expense		34			12			—			46			20			66
Step acquisition — equity interest re-measurement gain		(9	)		—			—			(9	)		—			(9	)
Other income		(4	)		(1	)		—			(5	)		—			(5	)
Total operating costs and expenses		1,206			795			—			2,001			1,079			3,080
Operating income		63			44			—			107			14			121
Interest expense, net		(29	)		—			—			(29	)		—			(29	)
Earnings from unconsolidated affiliates		38			—			(14	)		24			(1	)		23
Income before income taxes		72			44			(14	)		102			13			115
Income tax expense		(1	)		(1	)		—			(2	)		—			(2	)
Net income		71			43			(14	)		100			13			113
Net income attributable to noncontrolling interests		(9	)		—			—			(9	)		(3	)		(12	)
Net income attributable to partners	$	62		$	43		$	(14	)	$	91		$	10		$	101

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented within 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%.

(d) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

The currently reported results are not intended to reflect actual results that would have occurred if the acquired business had been consolidated during the period presented.

On July 3, 2012, we acquired the Crossroads processing plant and associated gathering system from Penn Virginia Resource Partners, L.P. for $63 million. The acquisition was financed at closing with borrowings under our revolving credit facility. The Crossroads system, located in the southeastern portion of Harrison County in East Texas, includes approximately 8 miles of gas gathering pipeline, an 80 MMcf/d cryogenic processing plant, approximately 20 miles of NGL pipeline and a 50% ownership interest in an approximately 11-mile residue gas pipeline, or CrossPoint Pipeline, LLC, which we have accounted for as an unconsolidated affiliate using the equity method. The Crossroads system is a part of our East Texas system, which is included in our Natural Gas Services segment.

We have accounted for the Crossroads business combination based on estimates of the fair value of assets acquired and liabilities assumed, including: property, plant and equipment; the equity investment in CrossPoint Pipeline, LLC; a liability for a firm transportation agreement which expires in 2015; and a gas purchase agreement under which a portion of those firm transportation payments are recoverable. Expected cash payments and receipts have been recorded at their estimated fair value and

20

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

are included in other current liabilities, other long-term liabilities, and accounts receivable as of the acquisition date. The preliminary estimates of the fair value of identifiable assets acquired and liabilities assumed are subject to revisions, which may result in adjustments to the preliminary values as additional information relative to the fair value of assets and liabilities becomes available. The values assigned to the assets acquired and liabilities assumed may change in subsequent financial statements pending the final estimates of fair value. The following table summarizes the aggregate consideration and fair value of the identifiable assets acquired and liabilities assumed in the acquisition of Crossroads as of the acquisition date:

	July 3, 2012
	(Millions)
Aggregate consideration	$	63
Accounts receivable	$	4
Property, plant and equipment		63
Investments in unconsolidated affiliates		6
Other current liabilities		(4	)
Other long-term liabilities		(6	)
Total	$	63

The results of operations for acquisitions accounted for as a business combination are included in our results subsequent to the date of acquisition. Accordingly, total operating revenues of $22 million and net income of $1 million associated with Crossroads from the acquisition date to December 31, 2012 are included in our consolidated statement of operations.

Supplemental 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. The following tables present unaudited supplemental pro forma information for the consolidated statement of operations for the years ended December 31, 2012 and 2011, as if the acquisition of Crossroads had occurred at the beginning of the earliest period presented.

	Year Ended December 31, 2012
	DCP Midstream Partners, LP			Acquisition of Crossroads  (a)		DCP Midstream Partners, LP Pro Forma
	(Millions)
Total operating revenues	$	2,761		$	27	$	2,788
Net income attributable to partners	$	198		$	2	$	200
Less:
Net income attributable to predecessor operations		(32	)		—		(32	)
General partner’s interest in net income		(41	)		—		(41	)
Net income allocable to limited partners	$	125		$	2	$	127
Net income per limited partner unit — basic and diluted	$	2.28		$	0.03	$	2.31

(a) The year ended December 31, 2012 includes the financial results of Crossroads for the period from January 1, 2012 through July 2, 2012.

21

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Year Ended December 31, 2011
	DCP Midstream Partners, LP			Acquisition of Crossroads		DCP Midstream Partners, LP Pro Forma
	(Millions)
Total operating revenues	$	3,700		$	114	$	3,814
Net income attributable to partners	$	163		$	4	$	167
Less:
Net income attributable to predecessor operations		(63	)		—		(63	)
General partner’s interest in net income		(25	)		—		(25	)
Net income allocable to limited partners	$	75		$	4	$	79
Net income per limited partner unit — basic	$	1.73		$	0.09	$	1.82
Net income per limited partner unit — diluted	$	1.72		$	0.09	$	1.81

The supplemental pro forma total operating revenues for the year ended December 31, 2012 was adjusted to eliminate $5 million related to a contractual gas processing arrangement between us and Crossroads during the period.

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

On July 2, 2012, we acquired the minority ownership interests in two non-operated Mont Belvieu fractionators, or the Mont Belvieu fractionators, from DCP Midstream, LLC for aggregate consideration of $200 million, plus $5 million in working capital and other customary purchase price adjustments. $60 million of the aggregate consideration was financed by the issuance at closing of 1,536,098 of our common units to DCP Midstream, LLC. We entered into a 2-year Term Loan Agreement to fund the remaining $140 million. The $175 million excess purchase price over the carrying value of the acquired investments was recorded as a decrease in common unitholders’ equity. The minority ownership interests include a 12.5% interest in the Enterprise fractionator, which is operated by Enterprise Products Partners L.P., and a 20% interest in the Mont Belvieu 1 fractionator, which is operated by ONEOK Partners. We have accounted for the results of the minority ownership interests in the Mont Belvieu fractionators prospectively from the date of acquisition. The Mont Belvieu fractionators are accounted for as unconsolidated affiliates using the equity method and are included in our NGL Logistics segment.

On April 12, 2012, we acquired a 10% ownership interest in the Texas Express Pipeline joint venture from the operator, Enterprise Products Partners, L.P., or Enterprise, representing an approximate investment of $85 million in the joint venture. At closing, we paid $11 million for our 10% ownership interest in the Texas Express Pipeline joint venture, representing our proportionate share of the investment through the closing date, and will be responsible for spending an approximate $75 million for our share of the remaining construction costs of the pipeline. Originating near Skellytown in Carson County, Texas, the 20-inch diameter Texas Express Pipeline will extend approximately 580 miles to Enterprise’s natural gas liquids fractionation and storage complex at Mont Belvieu, Texas, and will provide access to other third party facilities in the area. The Texas Express Pipeline will have an initial capacity of approximately 280 MBbls/d and as of December 31, 2012, has in place long-term, fee-based, ship-or-pay transportation commitments of 252 MBbls/d, including a commitment from DCP Midstream, LLC of 20 MBbls/d. The pipeline is expected to be completed in mid-2013.

On January 3, 2012, we acquired the remaining 49.9% interest in East Texas from DCP Midstream, LLC for consideration of $165 million, subject to working capital and other customary purchase price adjustments. $132 million of the consideration was financed with proceeds from a 2-year Term Loan Agreement. The remaining $33 million consideration was financed by the issuance at closing of an aggregate of 727,520 of our common units to DCP Midstream, LLC. The $23 million deficit purchase price under the carrying value of the acquired net assets and the $33 million of common units issued as consideration for this acquisition were recorded as an increase in common unitholders’ equity. 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 have included the results of the remaining 49.9% interest in East Texas prospectively from the date of contribution.

22

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Omnibus Agreement and Other General and Administrative Charges

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

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,
	2012		2011		2010
	(Millions)
Omnibus Agreement	$	26	$	10	$	10
Other fees — DCP Midstream, LLC		31		46		42
Total — DCP Midstream, LLC	$	57	$	56	$	52

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 an annual fee under the Omnibus Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering.

On January 3, 2012, we extended the omnibus agreement through December 31, 2012 for an annual fee of $18 million, with the primary increase resulting from the acquisition of the remaining 49.9% interest in East Texas. On March 30, 2012, in conjunction with our acquisition of the remaining 66.67% interest in Southeast Texas, we increased the annual fee we pay to DCP Midstream, LLC under the agreement by $10 million, prorated for the remainder of the 2012 calendar year. These fees were previously allocated to East Texas and Southeast Texas. In July 2012, in conjunction with our acquisition of the minority ownership interests in the Mont Belvieu fractionators, we increased the annual fee we pay to DCP Midstream, LLC by less than $1 million, prorated for the remainder of the 2012 calendar year. As a result of these transactions, the annual fee payable in future years to DCP Midstream, LLC will be $29 million. The Omnibus Agreement also addresses the following matters:

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

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

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

Before the addition of East Texas and Southeast Texas to the Omnibus Agreement, East Texas and Southeast Texas incurred general and administrative expenses directly from DCP Midstream, LLC. During each of the years ended December 31, 2011 and 2010, East Texas incurred $8 million, and during the years ended December 31, 2012, 2011 and 2010, Southeast Texas incurred $3 million, $10 million and $12 million, respectively, 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, are covered by the Omnibus Agreement.

23

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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 million for each of the years ended December 31, 2012 and 2011 and $2 million for the year ended December 31, 2010. These amounts include allocated expenses, including professional services, insurance, internal audit and various other corporate functions. The Eagle Ford system incurred $27 million in general and administrative expenses directly from DCP Midstream, LLC for each of the years ended December 31, 2012 and 2011 and $20 million in general and administrative expenses directly from DCP Midstream, LLC for the year ended December 31, 2010.

On February 14, 2013, we entered into a Services Agreement with DCP Midstream, LLC, which replaces the Omnibus Agreement, whereby DCP Midstream, LLC will continue to provide us with the general and administrative services previously provided under the Omnibus Agreement. The annual fee payable in future years to DCP Midstream, LLC under the Services Agreement will be consistent with the fee structure previously payable under the Omnibus Agreement, and will be $29 million for 2013. Pursuant to the Services Agreement, we will reimburse DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.

Competition

None of DCP Midstream, LLC, or any of its affiliates, including Spectra Energy and Phillips 66, 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 Phillips 66, 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, 2012, 2011 and 2010. 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 derivative transactions directly with DCP Midstream, LLC, whereby DCP Midstream, LLC 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.

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 an interruptible transportation agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand 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.

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.

24

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

As a result of a downstream outage, certain of our assets were required to curtail NGL production during 2012. DCP Midstream, LLC has reimbursed us for the impact of the curtailment and accordingly, we have recorded $3 million to sales of natural gas, propane, NGLs and condensate to affiliates and less than $1 million to transportation, processing and other to affiliates in the consolidated statements of operations for the year ended December 31, 2012.

In conjunction with our acquisitions of our East Texas and Southeast Texas systems, which are part of our Natural Gas Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on East Texas and Southeast Texas capital projects. These reimbursements are for specific 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 $5 million, $18 million and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of $5 million for the year ended December 31, 2012.

During the year ended December 31, 2011, East Texas received $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 $7 million to our consolidated statement of operations in “sales of natural gas, propane, NGLs and condensate”, with $5 million representing DCP Midstream, LLC’s portion in “net income attributable to noncontrolling interests.”

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 million for net proceeds of $3 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 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 $3 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.

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.

With respect to our Wattenberg pipeline, 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.

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 Colorado at our DJ Basin NGL fractionators under agreements that are effective through March 2018. We incurred fees of less than $1 million during each of the years ended December 31, 2012 and 2011, which are included in operating and maintenance expense in the consolidated statements of operations.

DCP Midstream, LLC has issued parental guarantees, totaling $25 million as of December 31, 2012, 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 a fee of 0.5% per annum on these outstanding guarantees.

Spectra Energy

We had propane supply agreements with Spectra Energy that expired in April 2012, which provided us propane supply at our marine terminals, included in our Wholesale Propane Logistics segment, for up to approximately 185 million gallons of propane annually.

25

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

ConocoPhillips and Phillips 66

Prior to May 2012, DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, was owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. In May 2012, ConocoPhillips separated its business into two stand-alone publicly traded companies. As a result of this transaction, DCP Midstream, LLC is no longer owned 50% by ConocoPhillips. ConocoPhillips’ 50% ownership interest in DCP Midstream, LLC has been transferred to the new downstream company, Phillips 66.

We have multiple agreements with Phillips 66 and its affiliates, and anticipate continuing to sell to Phillips 66 and its affiliates in the ordinary course of business. Prior to ConocoPhillips’ separation in May 2012, these agreements were with ConocoPhillips. We continue to have agreements with ConocoPhillips, including fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements; however, we do not consider ConocoPhillips to be a related party effective May 1, 2012.

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:

	Year Ended December 31,
	2012		2011		2010
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	1,630	$	2,259	$	1,808
Transportation, processing and other	$	50	$	27	$	13
Purchases of natural gas, propane and NGLs	$	135	$	189	$	187
Gains (losses) from commodity derivative activity, net	$	53	$	1	$	(2	)
Operating and maintenance expense	$	1	$	1	$	—
General and administrative expense	$	57	$	56	$	52
Spectra Energy:
Purchases of natural gas, propane and NGLs (a)	$	166	$	321	$	164
Other income	$	—	$	—	$	3
ConocoPhillips (b):
Sales of natural gas, propane, NGLs and condensate	$	9	$	57	$	45
Transportation, processing and other	$	3	$	9	$	11
Purchases of natural gas, propane and NGLs	$	67	$	139	$	30
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	2	$	6	$	5

(a) Includes a $17 million payment received in December 2010 for reimbursement of damages we incurred when an international propane supplier breached its contract with Spectra Energy.

(b) In connection with the Phillips 66 separation, ConocoPhillips is not considered to be a related party for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.

26

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

We had balances with affiliates as follows:

	December 31,
	2012			2011
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	132		$	100
Accounts payable	$	66		$	23
Unrealized gains on derivative instruments—current	$	48		$	1
Unrealized gains on derivative instruments— long term	$	64		$	—
Unrealized losses on derivative instruments—current	$	(11	)	$	(1	)
Unrealized losses on derivative instruments—long term	$	—		$	(3	)
Spectra Energy:
Accounts payable	$	5		$	29
ConocoPhillips (a):
Accounts receivable	$	—		$	7
Accounts payable	$	—		$	18
Unrealized gains on derivative instruments—current	$	—		$	3
Unrealized losses on derivative instruments—current	$	—		$	(2	)
Unconsolidated affiliates:
Accounts payable	$	1		$	2

(a) In connection with the Phillips 66 separation, ConocoPhillips is not considered to be a related party for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.

27

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

5. Inventories

Inventories were as follows:

	December 31,		December 31,
	2012		2011
	(Millions)
Natural gas	$	22	$	26
NGLs		54		64
Total inventories	$	76	$	90

We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the consolidated statements of operations. We recognized $19 million and $6 million in lower of cost or market adjustments during the year ended December 31, 2012 and 2011, respectively.

6. Property, Plant and Equipment

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

	Depreciable		December 31,			December 31,
	Life		2012			2011
			(Millions)
Gathering and transmission systems		20 — 50 Years	$	1,921		$	1,741
Processing, storage, and terminal facilities		35 — 60 Years		1,103			1,006
Other		3 — 30 Years		31			26
Construction work in progress				561			332
Property, plant and equipment				3,616			3,105
Accumulated depreciation				(1,066	)		(991	)
Property, plant and equipment, net			$	2,550		$	2,114

Interest capitalized on construction projects in 2012, 2011 and 2010, was $7 million, $2 million and less than $1 million, respectively.

We revised the depreciable lives for our gathering and transmission systems, processing, storage and terminal facilities, and other assets effective April 1, 2012. The key contributing factors to the change in depreciable lives is an increase in the estimated remaining economically recoverable reserves resulting from the development of techniques that improve commodity production in the regions our assets serve. Advances in extraction processes, along with better technology used to locate commodity reserves, is giving producers greater access to unconventional commodities. Based on our property, plant and equipment as of April 1, 2012, the new remaining depreciable lives resulted in an approximate $52 million reduction in depreciation expense for the year ended December 31, 2012. This change in our estimated depreciable lives increased net income per limited partner unit by $0.95 for the year ended December 31, 2012.

In connection with our evaluation of useful lives, we corrected the classification for certain assets within the presentation of our major classes of property, plant and equipment as of December 31, 2011.

Depreciation expense was $81 million, $125 million and $110 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Asset Retirement Obligations — As of December 31, 2012 and 2011, we had asset retirement obligations of $23 million and $17 million, respectively, included in other long-term liabilities in the consolidated balance sheets. During the first quarter of 2012, we recorded a change in estimate to increase our asset retirement obligations by approximately $6 million. The change in estimate was primarily attributable to a reassessment of anticipated timing of settlements and of the original asset retirement obligation estimated amounts. Accretion benefit was less than $1 million for the year ended December 31, 2012 and accretion expense was $1 million for each of the years ended December 31, 2011 and 2010.

28

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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 carrying amount of goodwill is as follows:

	December 31,
	2012		2011
	(Millions)
Beginning of period	$	154	$	151
Acquisitions		—		3
End of period	$	154	$	154

The carrying value of goodwill as of December 31, 2012 and 2011 was $82 million for each of the years for our Natural Gas Services segment, $35 million for each of the years for our NGL Logistics segment, and $37 million for each of the years for our Wholesale Propane Logistics segment.

We performed our annual goodwill assessment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We used a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including 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. 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,
	2012			2011
	(Millions)
Gross carrying amount	$	164		$	164
Accumulated amortization		(27	)		(19	)
Intangible assets, net	$	137		$	145

For the years December 31, 2012, 2011 and 2010, we recorded amortization expense of $8 million, $8 million and $5 million, respectively. As of December 31, 2012, the remaining amortization periods ranged from approximately 9 years to 23 years, with a weighted-average remaining period of approximately 18 years.

29

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Estimated future amortization for these intangible assets is as follows:

Estimated Future Amortization
(Millions)
2013	$	8
2014		8
2015		8
2016		8
2017		8
Thereafter		97
Total	$	137

8. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

				Carrying Value as of
	Percentage Ownership			December 31, 2012		December 31, 2011
				(Millions)
Discovery Producer Services LLC		40	%	$	223	$	107
Texas Express Pipeline		10	%		41		—
Mont Belvieu Enterprise Fractionator		12.5	%		19		—
Mont Belvieu 1 Fractionator		20	%		14		—
CrossPoint Pipeline, LLC		50	%		6		—
Other		various			1		1
Total investments in unconsolidated affiliates				$	304	$	108

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $30 million and $33 million at December 31, 2012 and 2011, respectively, which is associated with, and is being amortized over, the life of the underlying long-lived assets of Discovery.

There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu 1 of $6 million at December 31, 2012, which is associated with, and is being amortized over, the life of the underlying long-lived assets of Mont
Belvieu 1.

Earnings from investments in unconsolidated affiliates were as follows:

	Year Ended December 31,
	2012		2011		2010
	(Millions)
Discovery Producer Services LLC	$	15	$	23	$	23
Mont Belvieu Enterprise Fractionator		5		—		—
Mont Belvieu 1 Fractionator		6		—		—
CrossPoint Pipeline, LLC		—		—		—
Other (a)		—		—		—
Total earnings from unconsolidated affiliates	$	26	$	23	$	23

(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.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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

	Year Ended December 31,
	2012		2011		2010 (a)
	(Millions)
Statements of operations:
Operating revenue	$	293	$	213	$	212
Operating expenses	$	190	$	163	$	160
Net income	$	103	$	50	$	50

(a) The combined financial information includes the results of Black Lake through July 30, 2010.

	December 31,
	2012			2011
	(Millions)
Balance sheet:
Current assets	$	129		$	38
Long-term assets		1,288			364
Current liabilities		(75	)		(20	)
Long-term liabilities		(43	)		(29	)
Net assets	$	1,299		$	353

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 or prices obtained through external sources, 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. Fair 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. 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

31

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

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

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11 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.

32

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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

Interest Rate Derivative Assets and Liabilities

We use interest rate swap 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.

The following table presents the financial instruments carried at fair value as of December 31, 2012 and 2011, by consolidated balance sheet caption and by valuation hierarchy, as described above:

33

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	December 31, 2012											December 31, 2011
	Level 1		Level 2			Level 3			Total Carrying Value			Level 1		Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets (a):
Commodity derivatives	$	—	$	9		$	40		$	49		$	—	$	40		$	1		$	41
Long-term assets (b):
Commodity derivatives	$	—	$	5		$	65		$	70		$	—	$	6		$	1		$	7
Current liabilities (c):
Commodity derivatives	$	—	$	(26	)	$	(1	)	$	(27	)	$	—	$	(43	)	$	(1	)	$	(44	)
Interest rate derivatives	$	—	$	(4	)	$	—		$	(4	)	$	—	$	(16	)	$	—		$	(16	)
Long-term liabilities (d):
Commodity derivatives	$	—	$	(6	)	$	—		$	(6	)	$	—	$	(28	)	$	—		$	(28	)
Interest rate derivatives	$	—	$	(2	)	$	—		$	(2	)	$	—	$	(5	)	$	—		$	(5	)

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

Changes in Levels 1 and 2 Fair Value Measurements

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. 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. The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. 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. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer between Level 1 and Level 2 would be reflected in a table as Transfers in/out of Level 1/Level 2. During the year ended December 31, 2012, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.

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. The significant unobservable inputs used in determining fair value include adjustments by other market based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. 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 into/out of Level 3” caption.

34

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.

	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(Millions)
Year ended December 31, 2012 (a):
Beginning balance	$	1		$	1		$	(1	)	$	—
Net realized and unrealized gains included in earnings (d)		14			2			—			—
Transfers into Level 3 (c)		—			—			—			—
Transfers out of Level 3 (c)		—			—			—			—
Settlements		(2	)		—			—			—
Purchases		27			62			—			—
Ending balance	$	40		$	65		$	(1	)	$	—
Net unrealized gains (losses) still held included in earnings (d)	$	13		$	2		$	—		$	—
Year ended December 31, 2011 (b):
Beginning balance	$	—		$	—		$	—		$	—
Net realized and unrealized gains (losses) included in earnings (d)		2			1			(1	)		—
Transfers into Level 3 (c)		—			—			—			—
Transfers out of Level 3 (c)		—			—			—			—
Settlements		(1	)		—			—			—
Ending balance	$	1		$	1		$	(1	)		—
Net unrealized gains (losses) still held included in earnings (d)	$	1		$	1		$	(1	)	$	—
Year ended December 31, 2010:
Beginning balance	$	1		$	1		$	(2	)	$	—
Net realized and unrealized gains (losses) included in earnings (d)		2			—			—			—
Transfers into Level 3 (c)		—			—			—			—
Transfers out of Level 3 (c)		—			—			—			—
Purchases, Issuances and Settlements, net		(3	)		(1	)		2			—
Ending balance	$	—		$	—		$	—		$	—
Net unrealized gains (losses) still held included in earnings (d)	$	—		$	—		$	—		$	—

(a) There were no issuances and sales of derivatives for the year ended December 31, 2012.

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

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

(d) Represents the amount of total gains or losses for the year, 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

During years ended December 31, 2012, 2011 and 2010, we had no 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.

35

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs

We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.

Product Group	Fair Value			Forward Curve Range
	(Millions)
Assets
NGLs	$	99		$0.25-$2.13	Per gallon
Natural Gas	$	6		$3.69-$4.48	Per MMBtu
Liabilities
Natural Gas	$	(1	)	$3.81-$4.27	Per MMBtu

Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

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

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.

36

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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. Derivative instruments are carried at fair value. Each of the carrying and fair values of outstanding balances under our Credit Agreement are $525 million as of December 31, 2012, and $497 million as of December 31, 2011. The carrying value of the 2.50% Senior Notes was $500 million as of December 31, 2012, which approximated fair value. The carrying and fair values of the 4.95% Senior Notes are $350 million and $374 million, respectively, as of December 31, 2012. The carrying and fair values of the 3.25% Senior Notes are $250 million and $259 million, respectively, as of December 31, 2012. The carrying value of the 3.25% Senior Notes as of December 31, 2011 was $250 million, which approximated fair value. We determine the fair value of our Credit Agreement 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. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy.

10. Debt

Long-term debt was as follows:

	December 31, 2012			December 31, 2011
	(Millions)
Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.47% and 1.69%, respectively, due November 10, 2016 (a)	$	525		$	497
Debt Securities
Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017		500			—
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022		350			—
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015		250			250
Unamortized discount		(5	)		—
Total long-term debt	$	1,620		$	747

(a) $150 million has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.94% to 2.99%, for a net effective rate of 2.25% on the $525 million of outstanding debt under our revolving credit facility as of December 31, 2012. $450 million was 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 million of outstanding debt under our revolving credit facility as of December 31, 2011.

Credit Agreement

We have a $1 billion revolving credit facility that matures November 10, 2016, or the Credit Agreement.

At December 31, 2012 and 2011, we had $1 million of letters of credit issued and outstanding under the Credit Agreement and the Prior Credit Agreement. As of December 31, 2012, the unused capacity under the Credit Agreement was $474 million, which was available for general working capital purposes.

Our borrowing capacity is limited at December 31, 2012 by the Credit Agreement’s financial covenant requirements. Except in the case of a default, amounts borrowed under our Credit Agreement will not mature prior to the November 10, 2016 maturity date.

37

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Under the Credit Agreement, indebtedness under the revolving credit facility bears interest at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current 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 of 0.25% based on our current credit rating. The revolving credit facility incurs an annual facility fee of 0.25% based on our current 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 following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.

Debt Securities

On November 27, 2012, we issued $500 million of our 2.50% 5-year Senior Notes due December 1, 2017. We received net proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discounts of $6 million. Interest on the notes will be paid semi-annually on June 1 and December 1 of each year, commencing June 1, 2013. The notes will mature on December 1, 2017, 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.

On March 13, 2012, we issued $350 million of our 4.95% 10-year Senior Notes due April 1, 2022. We received net proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discounts of $4 million, which we used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under our Term Loan and Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on April 1, 2022, 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.

On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds of $248 million, net of underwriters’ fees, related expense and unamortized discounts of $2 million, which we used to repay funds borrowed under the revolver portion of our Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on October 1, 2015, unless redeemed prior to maturity. The underwriters’ fees and related expense 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 any of these notes, and they are redeemable at a premium at our option.

Term Loan Agreements

On November 2, 2012, we entered into a 2-year Term Loan Agreement and borrowed $343 million to fund the cash portion of the acquisition of a 33.33% interest in the Eagle Ford system. On July 2, 2012, we entered into a 2-year Term Loan Agreement and borrowed $140 million to fund the cash portion of the acquisition of the Mont Belvieu fractionators. In November 2012, we repaid both the term loans with proceeds from our 2.50% 5-year Senior Notes.

On January 3, 2012, we entered into a 2-year Term Loan Agreement and borrowed $135 million which was used to fund the cash portion of the acquisition of the remaining 49.9% interest in East Texas. In March 2012, we repaid the term loan with proceeds from our 4.95% 10-year Senior Notes.

38

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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

	Debt Maturities
	(Millions)
2013	$	—
2014		—
2015		250
2016		525
Thereafter		850
		1,625
Unamortized discount		(5	)
Total	$	1,620

11. 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. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices, however there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. During 2012, the relationship of NGLs to crude oil has been lower than historical relationships, however a significant amount of our NGL hedges from 2012 through 2015 are direct product hedges. 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.

39

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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, including fixed price sales. 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 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 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.

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 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 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 — On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas and commodity derivative hedge instruments (also referred to as the NGL Hedge) 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 the forecasted purchase of natural gas in June, July and August 2013, 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 $3 million as of December 31, 2012 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 $3 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

40

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Interest Rate Risk

We mitigate a portion of our interest rate risk with interest rate swaps that reduce our exposure to market rate fluctuations by converting variable interest rates on our existing debt to fixed interest rates. 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.

At December 31, 2011, we had interest rate swap agreements totaling $450 million, of which we had designated $425 million as cash flow hedges and accounted for the remaining $25 million under the mark-to-market method of accounting. In March 2012, we paid down a portion of the revolving credit facility and, as a result, we discontinued cash flow hedge accounting on $225 million of our interest rate swap agreements. $300 million of swap agreements settled in Q2 2012.

At December 31, 2012, we had interest rate swap agreements extending through June 2014 totaling $150 million, which are designated as cash flow hedges. 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, 2012, $150 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 2.99%, and receive interest payments based on the one-month LIBOR.

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.

On March 8, 2012, we settled $195 million of our forward-starting interest rate swap agreements for $7 million. The remaining net deferred losses of $5 million in AOCI will be amortized into interest expense associated with our long-term debt offering through 2022.

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, 2012, 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.

41

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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, 2012, we had $22 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, 2012 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, 2012, 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 $20 million.

As of December 31, 2012, we had $150 million of individual interest rate swap instruments that were in a net liability position of $6 million 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.

Unconsolidated Affiliates

Discovery Producer Services LLC, one of our unconsolidated affiliates, entered into agreements with a pipe vendor denominated in a foreign currency in connection with the expansion of the natural gas gathering pipeline system in the deepwater Gulf of Mexico, the Keathley Canyon Connector. Discovery entered into certain foreign currency derivative contracts to mitigate a portion of the foreign currency exchange risks which were designated as cash flow hedges. As these hedges are owned by Discovery, an unconsolidated affiliate, we include the impact to AOCI on our consolidated balance sheet.

Collateral

DCP Midstream, LLC had issued and outstanding parental guarantees totaling $25 million in favor of certain counterparties to our commodity derivative instruments. These parental guarantees reduce the amount of cash we may be required to post as collateral. As of December 31, 2012, we had no cash collateral posted with counterparties to our commodity derivative instruments.

Offsetting

Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments:

42

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
Description	December 31, 2012									December 31, 2011
Assets:
Commodity derivatives	$	119		$	(10	)	$	109		$	48		$	(7	)	$	41
Interest rate derivatives	$	—		$	—		$	—		$	—		$	—		$	—
Liabilities:
Commodity derivatives	$	(33	)	$	10		$	(23	)	$	(72	)	$	7		$	(65	)
Interest rate derivatives	$	(6	)	$	—		$	(6	)	$	(21	)	$	—		$	(21	)

(a) There is no cash collateral pledged or received against these positions.

Summarized Derivative Information

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

	December 31, 2012			December 31, 2011
	(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(6	)	$	(2	)
Interest rate cash flow hedges:
Net deferred losses in AOCI		(10	)		(19	)
Foreign currency cash flow hedges (a):
Net deferred gain in AOCI		1			—
Total AOCI	$	(15	)	$	(21	)

(a) Relates to Discovery, our unconsolidated affiliate.

43

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

The fair value of our derivative instruments that are designated as hedging instruments and 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, 2012		December 31, 2011		Balance Sheet Line Item	December 31, 2012			December 31, 2011
	(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	$	(3	)	$	—
Unrealized gains on derivative instruments – long-term		—		—	Unrealized losses on derivative instruments – long-term		—			(3	)
	$	—	$	—		$	(3	)	$	(3	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments – current	$	—	$	—	Unrealized losses on derivative instruments – current	$	(4	)	$	(16	)
Unrealized gains on derivative instruments – long-term		—		—	Unrealized losses on derivative instruments – long-term		(2	)		(5	)
	$	—	$	—		$	(6	)	$	(21	)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments – current	$	49	$	41	Unrealized losses on derivative instruments – current	$	(24	)	$	(44	)
Unrealized gains on derivative instruments – long-term		70		7	Unrealized losses on derivative instruments – long-term		(6	)		(25	)
	$	119	$	48		$	(30	)	$	(69	)
Interest rate derivatives:					Interest rate 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		—			—
	$	—	$	—		$	—		$	—

44

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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 for each of the years ended December 31, 2012 and 2011:

	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
	2012			2011			2012			2011			2012			2011			12 Months
	(Millions)						(Millions)						(Millions)						(Millions)
Interest rate derivatives	$	(1	)	$	(12	)	$	(10	)	$	(21	)(a)	$	(2	)	$	—	(a)(d)	$	(4	)
Commodity derivatives	$	(1	)	$	(1	)	$	—		$	—	(b)	$	—		$	—	(c)	$	—
Foreign currency derivatives (e)	$	1		$	—		$	—		$	—		$	—		$	—		$	—

(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, 2012 and 2011, 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. The ineffective portion is included in gains (losses) from commodity derivative activity, net – affiliates in our consolidated statements of operations.

(d) For the year ended December 31, 2012, less than $1 million of derivative 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.

(e) Relates to Discovery, our unconsolidated affiliate.

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	2012		2011			2010
	(Millions)
Third party:
Realized	$	4	$	(36	)	$	16
Unrealized		13		43			(11	)
Gains from commodity derivative activity, net	$	17	$	7		$	5
Affiliates:
Realized	$	45	$	2		$	(1	)
Unrealized		8		(1	)		(1	)
Gains (losses) from commodity derivative activity, net — affiliates	$	53	$	1		$	(2	)

	Year Ended December 31,
Interest Rate Derivatives: Statements of Operations Line Item	2012			2011			2010
	(Millions)
Third party:
Realized	$	(7	)	$	(4	)	$	(1	)
Unrealized		7			5			3
Interest expense	$	—		$	1		$	2

45

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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

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

	December 31, 2012
	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  (Short) Position (MMBtu)
2013		(943,379	)		(8,887,980	)		(2,593,955	)		9,690,000
2014		(584,365	)		(4,712,880	)		(2,584,930	)		(1,350,000	)
2015		(401,865	)		(5,127,155	)		(2,491,250	)		—
2016		(183,000	)		—			—			—

	December 31, 2011
	Crude Oil			Natural Gas			Natural Gas Liquids			Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)			Net (Short) Long 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	)		—			—			—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of December 31, 2012, we have swaps with a notional value of $70 million and $80 million, which, in aggregate, exchange $150 million of our floating rate obligation to a fixed rate obligation through June 2014.

12. Partnership Equity and Distributions

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

In November 2012, we issued 1,912,663 common units to DCP Midstream, LLC as partial consideration for our 33.33% interest in the Eagle Ford system.

In July 2012, we issued 1,536,098 common units to DCP Midstream, LLC as partial consideration for the Mont Belvieu fractionators.

In July 2012, we closed a private placement of equity with a group of institutional investors in which we sold 4,989,802 common units at a price of $35.55 per unit, and received proceeds of $174 million net of offering costs.

In June 2012, we filed a universal shelf registration statement on Form S-3 with the SEC with an unlimited offering amount, to replace an existing shelf registration statement. The universal shelf registration statement allows us to issue additional common units and debt securities. As of February 22, 2013, we have issued no equity securities under this registration statement. Our 2.50% 5-year Senior Notes were issued under this registration statement.

46

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

In March 2012, we issued 5,148,500 common units at $47.42 per unit. We received proceeds of $234 million, net of offering costs.

In March 2012, we issued 1,000,417 common units to DCP Midstream, LLC as partial consideration for the remaining 66.67% interest in Southeast Texas.

In February 2012, we issued 30,701 common units under our 2005 Long-Term Incentive Plan, or 2005 LTIP, to employees as compensation for their service.

In January 2012, we issued 727,520 common units to DCP Midstream, LLC as partial consideration for the remaining 49.9% interest in East Texas.

In August 2011, we entered into an equity distribution agreement with a financial institution, as sales agent. The agreement provides for the offer and sale from time to time, through our sales agent, common units having an aggregate offering amount of up to $150 million. As of December 31, 2012, approximately $70 million aggregate offering price of our common units remains available for sale pursuant to this equity distribution agreement. During the three months ended December 31, 2012, we issued 254,265 of our common units pursuant to the equity distribution agreement, and received proceeds of $10 million, net of commissions and offering costs of $1 million. During the year ended December 31, 2012, we issued 1,147,654 of our common units pursuant to the equity distribution agreement, and received proceeds of $47 million, net of commissions and offering costs of $2 million. During the year ended December 31, 2011, we issued 761,285 of our common units pursuant to this equity distribution agreement, and received proceeds of $30 million from the issuance of these common units, net of commissions and offering costs of $1 million.

In March 2011, we issued 3,596,636 common units at $40.55 per unit. We received proceeds of $140 million, net of offering costs.

In February 2011, we issued 8,399 common 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 units at $34.96 per unit. We received proceeds of $96 million, net of offering costs.

In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93 million, net of offering costs.

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

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

• provide for the proper conduct of our business;

• comply with applicable law, any of our debt instruments or other agreements; 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, 2012. 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.

47

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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 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.

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 2012, 2011 and 2010:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 14, 2012	$	0.6800	$	53
August 14, 2012	$	0.6700	$	49
May 15, 2012	$	0.6600	$	43
February 14, 2012	$	0.6500	$	37
November 14, 2011	$	0.6400	$	35
August 12, 2011	$	0.6325	$	34
May 13, 2011	$	0.6250	$	33
February 14, 2011	$	0.6175	$	30
November 12, 2010	$	0.6100	$	27
August 13, 2010	$	0.6100	$	25
May 14, 2010	$	0.6000	$	25
February 12, 2010	$	0.6000	$	25

13. Equity-Based Compensation

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

	Year Ended December 31,
	2012		2011		2010
	(Millions)
Performance Phantom Units	$	1	$	5	$	1
Phantom Units		—		—		—
Restricted Phantom Units		1		2		2
Total compensation cost	$	2	$	7	$	3

48

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

On November 28, 2005, the board of directors of our General Partner adopted a Long-Term Incentive Plan, or the 2005 LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2005 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 issued and delivered pursuant to awards under the 2005 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.

On February 15, 2012, the board of directors of our General Partner adopted a 2012 LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provides for the grant of phantom units and the grant of DERs. The phantom units consist of a notional unit based on the value of common units or shares of the Partnership, Spectra Energy, ConocoPhillips and Phillips 66.

The LTIPs were administered by the compensation committee of the General Partner’s board of directors through 2012, and by the General Partner’s board of directors beginning in 2013. All awards are subject to cliff vesting.

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 classified 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 $2 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 is recognized ratably over each remaining vesting period.

We 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 did 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 Phantom Units — We have awarded Performance Phantom Units, or PPUs, pursuant to the LTIP to certain employees. PPUs generally vest in their entirety at the end of a three year performance period. The number of PPUs that will ultimately vest range, in value up to 200% of the outstanding PPUs, depending on the achievement of specified performance targets over three year performance periods. The final performance payout is determined by the board of directors of our General Partner. The DERs are paid in cash at the end of the performance period. Of the remaining PPUs outstanding at December 31, 2012, 3,633 units are expected to vest on December 31, 2013 and 6,377 units are expected to vest on December 31, 2014.

At December 31, 2012, there was less than $1 million of unrecognized compensation expense related to the PPUs that is expected to be recognized over a weighted-average period of 2 years. The following table presents information related to the PPUs:

49

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Units			Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2010		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		(50,720	)	$	10.05
Forfeited		—		$	—
Outstanding at December 31, 2011		27,210		$	35.69
Granted (a)		11,740		$	39.31
Vested (b)		(20,100	)	$	34.57
Forfeited		(7,760	)	$	38.97
Outstanding at December 31, 2012		11,090		$	39.24	$	41.24
Expected to vest (c)		10,010		$	39.24	$	41.24

(a) Includes the impact of conversion of the underlying securities granted under the 2012 LTIP.

(b) The units vested at 121%.

(c) Based on our December 31, 2012 estimated achievement of specified performance targets, the performance estimate for units granted in 2012 is 100%, and for units granted in 2011 is 100%. The estimated forfeiture rate for units granted in both 2012 and 2011 is 10%.

The estimate of PPUs 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 related to PPUs, including the related DERs:

	Year Ended December 31,
	2012		2011		2010
	(Millions)
Fair value of units vested	$	1	$	5	$	—
Unit-based liabilities paid	$	5	$	—	$	1

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.

As part of their director fees, we granted 4,000 Phantom Units during each of the years ended December 31, 2012 and 2011, respectively, and 5,200 Phantom Units during the year ended December 31, 2010, to directors. All of these units vested in their respective grant years, and were settled in units.

The DERs are paid in cash quarterly in arrears.

50

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

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, 2010		—		$	—
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		—		$	—
Granted		4,000		$	48.03
Vested		(4,000	)	$	48.03
Outstanding at December 31, 2012		—		$	—	$	—

The fair value of units vested related to Phantom Units was less than $1 million for the years ended December 31, 2012, 2011 and 2010.

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, 2012, 1,560 units are expected to vest on December 31, 2013 and 1,610 units are expected to vest on December 31, 2014. The DERs are paid in cash quarterly in arrears.

At December 31, 2012, there was less than $1 million of unrecognized compensation expense related to the RPUs that is expected to be recognized over a weighted-average period of 2 years. 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, 2010		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
Granted (a)		11,740		$	39.31
Vested		(19,060	)	$	37.31
Forfeited		(7,760	)	$	43.27
Outstanding at December 31, 2012		4,250		$	39.63	$	41.31
Expected to vest		3,170		$	39.76	$	41.34

(a) Includes the impact of conversion of the underlying securities granted under the 2012 LTIP.

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:

51

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Year Ended December 31,
	2012		2011		2010
	(Millions)
Fair value of units vested	$	1	$	3	$	1
Unit-based liabilities paid	$	2	$	1	$	—

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 30% for units granted in 2012 and 20% for units granted in 2011. 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.

14. Income Taxes

We are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for federal income tax purposes. Accordingly, we had no federal income tax expense for the years ended December 31, 2012 and 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 million of deferred tax liabilities resulting from built-in tax gains recognized in the transaction and recorded this as part of our preliminary acquisition accounting 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 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 million and less than $1 million, respectively, related to our estimated $35 million tax liability that resulted from our acquisition of Marysville. In 2011, the remaining $5 million estimated tax payable was reclassified to goodwill in our final acquisition 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. For the years ended December 31, 2011 and 2010, the state of Michigan imposed 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 was subject to a tax surcharge of 21.99%. The Michigan business tax was repealed for the year ended December 31, 2012.

Income tax expense consists of the following:

	Year Ended December 31,
	2012			2011			2010
	(Millions)
Current:
Federal income tax expense	$	—		$	(29	)	$	—
State income tax expense		(1	)		(2	)		(1	)
Deferred:
Federal income tax benefit		—			29			—
State income tax (expense) benefit		—			1			(1	)
Total income tax expense	$	(1	)	$	(1	)	$	(2	)

We had net long-term deferred tax liabilities of $6 million as of December 31, 2012 and 2011, included in other long-term liabilities on the consolidated balance sheets. These state deferred tax liabilities relate to our 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 master limited partnership, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states

52

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

15. 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.

Basic and diluted net income or loss per LPU is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the year. Diluted net income or loss 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 33,043 and 64,286 equivalent units during the years ended December 31, 2012 and 2011.

16. 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 (“Marysville”) on December 30, 2010 (the “Acquisition”). The Claim involves actions taken and time periods prior to our ownership of EE Group and Marysville, and includes several causes of action including claims of civil conspiracy, breach of fiduciary duty and fraud. We acquired a 90% interest in Marysville from Dart Energy Corporation, a 5% interest in Marysville from Prospect Street Energy, LLC and a 100% interest in EE Group, which owned the remaining 5% interest in Marysville. The Claimants seek, 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. In August 2012, we entered into a Settlement Agreement with the Claimants in which the Claimants have agreed that if an award is issued to the Claimants in the arbitration, the Claimants will not attempt to recover such an award from us. Notwithstanding that agreement, this matter 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.

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 flow.

53

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Insurance — We renewed our insurance policies in May, June and July 2012 for the 2012-2013 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 2012-2013 insurance year compared with the 2011-2012 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 2012-2013 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 2012-2013 insurance year.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Indemnification — DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors.

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 $14 million for the year ended December 31, 2012, and $15 million for each of the years ended December 31, 2011 and 2010. 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, 2012:

	(Millions)
2013	$	11
2014		6
2015		3
2016		2
2017		1
Thereafter		1
Total minimum rental payments	$	24

54

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

17. Business Segments

Our operations are located in the United States and are organized into three reporting segments: Natural Gas Services; NGL Logistics; and 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 East Texas system, our 80% interest in the Eagle Ford system, our 75% interest in the Colorado system, and our 40% 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, our 10% interest in the Texas Express NGL pipeline, the NGL storage facility in Michigan, the DJ Basin NGL fractionators in Colorado, our 12.5% interest in the Mont Belvieu Enterprise fractionator, and our 20% interest in the Mont Belvieu 1 fractionator.

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 distributors. The segment consists of six owned rail terminals, one owned marine 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.

55

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

The following tables set forth our segment information:

Year Ended December 31, 2012:

	Natural  Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,282		$	64		$	415		$	—		$	2,761
Gross margin (a)	$	478		$	64		$	42		$	—		$	584
Operating and maintenance expense		(162	)		(16	)		(15	)		—			(193	)
Depreciation and amortization expense		(81	)		(6	)		(2	)		—			(89	)
General and administrative expense		—			—			—			(74	)		(74	)
Earnings from unconsolidated affiliates		15			11			—			—			26
Interest expense		—			—			—			(42	)		(42	)
Income tax expense (b)		—			—			—			(1	)		(1	)
Net income (loss)		250			53			25			(117	)		211
Net income attributable to noncontrolling interests		(13	)		—			—			—			(13	)
Net income (loss) attributable to partners	$	237		$	53		$	25		$	(117	)	$	198
Net unrealized gains on derivative instruments (c)	$	20		$	—		$	1		$	—		$	21
Capital expenditures	$	467		$	12		$	4		$	—		$	483
Acquisitions net of cash acquired	$	715		$	30		$	—		$	—		$	745
Investments in unconsolidated affiliates	$	115		$	43		$	—		$	—		$	158

Year Ended December 31, 2011:

	Natural  Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Eliminations (f)			Total
	(Millions)
Total operating revenue	$	3,012		$	57		$	633		$	—		$	(2	)	$	3,700
Gross margin (a)	$	497		$	52		$	51		$	—		$	—		$	600
Operating and maintenance expense		(157	)		(16	)		(15	)		—			—			(188	)
Depreciation and amortization expense		(122	)		(8	)		(3	)		—			—			(133	)
General and administrative expense		—			—			—			(75	)		—			(75	)
Earnings from unconsolidated affiliates		23			—			—			—			—			23
Other operating income		—			1			—			—			—			1
Interest expense		—			—			—			(34	)		—			(34	)
Income tax expense (b)		—			—			—			(1	)		—			(1	)
Net income (loss)		241			29			33			(110	)		—			193
Net income attributable to noncontrolling interests		(30	)		—			—			—			—			(30	)
Net income (loss) attributable to partners	$	211		$	29		$	33		$	(110	)	$	—		$	163
Net unrealized gains on derivative instruments (c)	$	42		$	—		$	—		$	(2	)	$	—		$	40
Capital expenditures	$	371		$	9		$	4		$	—		$	—		$	384
Acquisitions net of cash acquired	$	122		$	30		$	—		$	—		$	—		$	152
Investments in unconsolidated affiliates	$	8		$	—		$	—		$	—		$	—		$	8

56

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

Year Ended December 31, 2010:

	Natural  Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,710		$	18		$	473		$	—		$	3,201
Gross margin (a)	$	401		$	13		$	29		$	—		$	443
Operating and maintenance expense		(138	)		(4	)		(13	)		—			(155	)
Depreciation and amortization expense		(111	)		(2	)		(2	)		—			(115	)
General and administrative expense		—			—			—			(66	)		(66	)
Earnings from unconsolidated affiliates		22			1			—			—			23
Other operating income		2			—			3			—			5
Step acquisition – equity interest re-measurement gain		—			9			—			—			9
Interest expense		—			—			—			(29	)		(29	)
Income tax expense (b)		—			—			—			(2	)		(2	)
Net income (loss)		176			17			17			(97	)		113
Net income attributable to noncontrolling interests		(12	)		—			—			—			(12	)
Net income (loss) attributable to partners	$	164		$	17		$	17		$	(97	)	$	101
Net unrealized gains on derivative instruments (c)	$	(9	)	$	—		$	(1	)	$	2		$	(8	)
Capital expenditures	$	173		$	11		$	1		$	—		$	185
Acquisitions net of cash acquired	$	79		$	135		$	68		$	—		$	282
Investments in unconsolidated affiliates	$	2		$	—		$	—		$	—		$	2

	December 31,
	2012		2011		2010
	(Millions)
Segment long-term assets:
Natural Gas Services	$	2,706	$	2,171	$	1,907
NGL Logistics (d)		340		250		222
Wholesale Propane Logistics		105		104		102
Other (e)		84		14		4
Total long-term assets		3,235		2,539		2,235
Current assets		368		373		372
Total assets	$	3,603	$	2,912	$	2,607

(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) For the years ended December 31, 2011 and 2010, income tax expense relates primarily to the Texas margin tax and the Michigan business tax. The Michigan business tax was repealed in 2012; accordingly, income tax expense for the year ended December 31, 2012 relates primarily to the Texas margin tax.

(c) Net unrealized gains or losses on derivative instruments represent non-cash derivative mark-to-market and is included in segment gross margin, along with cash settlements for our derivative contracts.

57

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

(d) 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.

(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 segment to our Wholesale Propane segment.

18. Supplemental Cash Flow Information

	Year Ended December 31,
	2012			2011		2010
	(Millions)
Cash paid for interest and income taxes:
Cash paid for interest, net of amounts capitalized	$	23		$	17	$	8
Cash paid for income taxes, net of income tax refunds	$	1		$	30	$	1
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	47		$	34	$	14
Other non-cash additions of property, plant and equipment	$	8		$	3	$	12
Acquisition related contingent consideration	$	—		$	—	$	3
Non-cash change in parent advances	$	(115	)	$	5	$	—

19. Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2012 and 2011 were as follows (millions, except per unit amounts):

2012	First			Second			Third			Fourth			Year Ended December 31, 2012
Total operating revenues	$	837		$	668		$	604		$	652		$	2,761
Operating income	$	46		$	96		$	9		$	77		$	228
Net income	$	38		$	87		$	10		$	76		$	211
Net income attributable to noncontrolling interests	$	(4	)	$	(2	)	$	(2	)	$	(5	)	$	(13	)
Net income attributable to partners	$	34		$	85		$	8		$	71		$	198
Net income (loss) allocable to limited partners	$	12		$	69		$	(9	)	$	52		$	124
Basic and diluted net income (loss) per limited partner unit	$	0.26		$	1.33		$	(0.16	)	$	0.87		$	2.28

2011	First			Second			Third			Fourth			Year Ended December 31, 2011
Total operating revenues	$	906		$	904		$	954		$	936		$	3,700
Operating income	$	14		$	77		$	85		$	29		$	205
Net income	$	10		$	74		$	83		$	26		$	193
Net income attributable to noncontrolling interests	$	(5	)	$	(13	)	$	(3	)	$	(9	)	$	(30	)
Net income attributable to partners	$	5		$	61		$	80		$	17		$	163
Net (loss) income allocable to limited partners	$	(11	)	$	35		$	59		$	(8	)	$	75
Basic net (loss) income per limited partner unit	$	(0.28	)	$	0.80		$	1.35		$	(0.19	)	$	1.73

58

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

20. 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 statements on Form S-3 filed with the SEC on May 26, 2010 and June 14, 2012, 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.

59

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Condensed Consolidating Balance Sheet December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	3		$	2		$	(3	)	$	2
Accounts receivable, net		—		—			239			—			239
Inventories		—		—			76			—			76
Other		—		—			51			—			51
Total current assets		—		3			368			(3	)		368
Property, plant and equipment, net		—		—			2,550			—			2,550
Goodwill and intangible assets, net		—		—			291			—			291
Advances receivable — consolidated subsidiaries		873		1,424			—			(2,297	)		—
Investments in consolidated subsidiaries		532		728			—			(1,260	)		—
Investments in unconsolidated affiliates		—		—			304			—			304
Other long-term assets		—		11			79			—			90
Total assets	$	1,405	$	2,166		$	3,592		$	(3,560	)	$	3,603
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	12		$	336		$	(3	)	$	345
Advances payable — consolidated subsidiaries		—		—			2,297			(2,297	)		—
Long-term debt		—		1,620			—			—			1,620
Other long-term liabilities		—		2			42			—			44
Total liabilities		—		1,634			2,675			(2,300	)		2,009
Commitments and contingent liabilities
Equity:
Partners’ equity:
Predecessor equity		—		—			357			—			357
Net equity		1,405		542			376			(1,260	)		1,063
Accumulated other comprehensive loss		—		(10	)		(5	)		—			(15	)
Total partners’ equity		1,405		532			728			(1,260	)		1,405
Noncontrolling interests		—		—			189			—			189
Total equity		1,405		532			917			(1,260	)		1,594
Total liabilities and equity	$	1,405	$	2,166		$	3,592		$	(3,560	)	$	3,603

(a) The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, 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 are 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, 2012, 2011 and 2010

	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	$	—	$	4		$	6		$	(2	)	$	8
Accounts receivable, net		—		—			232			—			232
Inventories		—		—			90			—			90
Other		—		—			43			—			43
Total current assets		—		4			371			(2	)		373
Property, plant and equipment, net		—		—			2,114			—			2,114
Goodwill and intangible assets, net		—		—			299			—			299
Advances receivable — consolidated subsidiaries		370		598			—			(968	)		—
Investments in consolidated subsidiaries		886		1,050			—			(1,936	)		—
Investments in unconsolidated affiliates		—		—			108			—			108
Other long-term assets		—		5			13			—			18
Total assets	$	1,256	$	1,657		$	2,905		$	(2,906	)	$	2,912
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19		$	525		$	(2	)	$	542
Advances payable — consolidated subsidiaries		—		—			968			(968	)		—
Long-term debt		—		747			—			—			747
Other long-term liabilities		—		5			56			—			61
Total liabilities		—		771			1,549			(970	)		1,350
Commitments and contingent liabilities
Equity:
Partners’ equity
Predecessor equity		—		—			628			—			628
Net equity		1,256		905			424			(1,936	)		649
Accumulated other comprehensive loss		—		(19	)		(2	)		—			(21	)
Total partners’ equity		1,256		886			1,050			(1,936	)		1,256
Noncontrolling interests		—		—			306			—			306
Total equity		1,256		886			1,356			(1,936	)		1,562
Total liabilities and equity	$	1,256	$	1,657		$	2,905		$	(2,906	)	$	2,912

(a) The financial information as of December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas, transfers of net assets between entities under common control that were accounted for as if the transfers occurred at the beginning of the period, and prior years are 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, 2012, 2011 and 2010

	Condensed Consolidating Statements of Operations Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,459		$	—		$	2,459
Transportation, processing and other		—		—			232			—			232
Gains from commodity derivative activity, net		—		—			70			—			70
Total operating revenues		—		—			2,761			—			2,761
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			2,177			—			2,177
Operating and maintenance expense		—		—			193			—			193
Depreciation and amortization expense		—		—			89			—			89
General and administrative expense		—		—			74			—			74
Total operating costs and expenses		—		—			2,533			—			2,533
Operating income		—		—			228			—			228
Interest expense, net		—		(41	)		(1	)		—			(42	)
Earnings from unconsolidated affiliates		—		—			26			—			26
Earnings from consolidated subsidiaries		198		239			—			(437	)		—
Income before income taxes		198		198			253			(437	)		212
Income tax expense		—		—			(1	)		—			(1	)
Net income		198		198			252			(437	)		211
Net income attributable to noncontrolling interests		—		—			(13	)		—			(13	)
Net income attributable to partners	$	198	$	198		$	239		$	(437	)	$	198

(a) The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, 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 are retrospectively adjusted to furnish comparative information similar to the pooling method.

62

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	198	$	198		$	252		$	(437	)	$	211
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings		—		10			—			—			10
Net unrealized (losses) gains on cash flow hedges		—		(1	)		1			—			—
Net unrealized losses on cash flow hedges – predecessor operations		—		—			(1	)		—			(1	)
Other comprehensive income from consolidated subsidiaries		9		—			—			(9	)		—
Total other comprehensive income		9		9			—			(9	)		9
Total comprehensive income		207		207			252			(446	)		220
Total comprehensive income attributable to noncontrolling interests		—		—			(13	)		—			(13	)
Total comprehensive income attributable to partners	$	207	$	207		$	239		$	(446	)	$	207

(a) The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, 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 are retrospectively adjusted to furnish comparative information similar to the pooling method.

63

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	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	$	—	$	—		$	3,487		$	—		$	3,487
Transportation, processing and other		—		—			205			—			205
Gains from commodity derivative activity, net		—		—			8			—			8
Total operating revenues		—		—			3,700			—			3,700
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			3,100			—			3,100
Operating and maintenance expense		—		—			188			—			188
Depreciation and amortization expense		—		—			133			—			133
General and administrative expense		—		—			75			—			75
Other income		—		—			(1	)		—			(1	)
Total operating costs and expenses		—		—			3,495			—			3,495
Operating income		—		—			205			—			205
Interest expense, net		—		(33	)		(1	)		—			(34	)
Earnings from unconsolidated affiliates		—		—			23			—			23
Earnings from consolidated subsidiaries		163		196			—			(359	)		—
Income before income taxes		163		163			227			(359	)		194
Income tax expense		—		—			(1	)		—			(1	)
Net income		163		163			226			(359	)		193
Net income attributable to noncontrolling interests		—		—			(30	)		—			(30	)
Net income attributable to partners	$	163	$	163		$	196		$	(359	)	$	163

(a) The financial information as of December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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.

64

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Condensed Consolidating Statements of Comprehensive Income Year Ended December 31, 2011 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	163	$	163		$	226		$	(359	)	$	193
Other comprehensive income (loss):
Reclassification of cash flow hedges into earnings		—		21			—			—			21
Net unrealized losses on cash flow hedges		—		(12	)		(1	)		—			(13	)
Net unrealized losses on cash flow hedges – predecessor operations		—		—			(2	)		—			(2	)
Other comprehensive income (loss) from consolidated subsidiaries		6		(3	)		—			(3	)		—
Total other comprehensive income (loss)		6		6			(3	)		(3	)		6
Total comprehensive income		169		169			223			(362	)		199
Total comprehensive income attributable to noncontrolling interests		—		—			(30	)		—			(30	)
Total comprehensive income attributable to partners	$	169	$	169		$	193		$	(362	)	$	169

(a) The financial information as of December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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.

65

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	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	$	—	$	—		$	3,038		$	—		$	3,038
Transportation, processing and other		—		—			160			—			160
Gains from commodity derivative activity, net		—		—			3			—			3
Total operating revenues		—		—			3,201			—			3,201
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		—		—			2,758			—			2,758
Operating and maintenance expense		—		—			155			—			155
Depreciation and amortization expense		—		—			115			—			115
General and administrative expense		—		—			66			—			66
Step acquisition — equity interest re-measurement gain		—		—			(9	)		—			(9	)
Other income		—		—			(5	)		—			(5	)
Total operating costs and expenses		—		—			3,080			—			3,080
Operating income		—		—			121			—			121
Interest expense, net		—		(29	)		—			—			(29	)
Earnings from unconsolidated affiliates		—		—			23			—			23
Earnings from consolidated subsidiaries		101		130			—			(231	)		—
Income before income taxes		101		101			144			(231	)		115
Income tax expense		—		—			(2	)		—			(2	)
Net income		101		101			142			(231	)		113
Net income attributable to noncontrolling interests		—		—			(12	)		—			(12	)
Net income attributable to partners	$	101	$	101		$	130		$	(231	)	$	101

(a) The financial information as of December 31, 2010 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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.

66

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Condensed Consolidating Statements of Comprehensive Income Year Ended December 31, 2010 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	101	$	101		$	142		$	(231	)	$	113
Other comprehensive income:
Reclassification of cash flow hedges into earnings		—		22			1			—			23
Net unrealized losses on cash flow hedges		—		(19	)		—			—			(19	)
Other comprehensive income from consolidated subsidiaries		4		1			—			(5	)		—
Total other comprehensive income		4		4			1			(5	)		4
Total comprehensive income		105		105			143			(236	)		117
Total comprehensive income attributable to noncontrolling interests		—		—			(12	)		—			(12	)
Total comprehensive income attributable to partners	$	105	$	105		$	131		$	(236	)	$	105

(a) The financial information as of December 31, 2010 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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.

67

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2012 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	(274	)	$	(866	)	$	1,223		$	(1	)	$	82
INVESTING ACTIVITIES:
Capital expenditures		—			—			(483	)		—			(483	)
Acquisitions, net of cash acquired		—			—			(745	)		—			(745	)
Investments in unconsolidated affiliates		—			—			(158	)		—			(158	)
Return of investment from unconsolidated affiliate		—			—			1			—			1
Proceeds from sale of assets		—			—			2			—			2
Net cash used in investing activities		—			—			(1,383	)		—			(1,383	)
FINANCING ACTIVITIES:
Proceeds from debt		—			2,665			—			—			2,665
Payments of debt		—			(1,792	)		—			—			(1,792	)
Payment of deferred financing costs		—			(8	)		—			—			(8	)
Proceeds from issuance of common units, net of offering costs		455			—			—			—			455
Excess purchase price over acquired assets		—			—			(225	)		—			(225	)
Net change in advances to predecessor from DCP Midstream, LLC		—			—			355			—			355
Distributions to common unitholders and general partner		(181	)		—			—			—			(181	)
Distributions to noncontrolling interests		—			—			(9	)		—			(9	)
Contributions from noncontrolling interests		—			—			25			—			25
Contributions from DCP Midstream, LLC		—			—			10			—			10
Net cash provided by (used in) financing activities		274			865			156			—			1,295
Net change in cash and cash equivalents		—			(1	)		(4	)		(1	)		(6	)
Cash and cash equivalents, beginning of year		—			4			6			(2	)		8
Cash and cash equivalents, end of year	$	—		$	3		$	2		$	(3	)	$	2

(a) The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, 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 are retrospectively adjusted to furnish comparative information similar to the pooling method.

68

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

	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	$	(38	)	$	(93	)	$	518		$	—		$	387
INVESTING ACTIVITIES:
Capital expenditures		—			—			(384	)		—			(384	)
Acquisitions, net of cash acquired		—			—			(152	)		—			(152	)
Investments in unconsolidated affiliates		—			—			(8	)		—			(8	)
Return of investment from unconsolidated affiliate		—			—			2			—			2
Proceeds from sale of assets		—			—			5			—			5
Net cash used in investing activities		—			—			(537	)		—			(537	)
FINANCING ACTIVITIES:
Proceeds from debt		—			1,524			—			—			1,524
Payments of debt		—			(1,425	)		—			—			(1,425	)
Payment of deferred financing costs		—			(4	)		—			—			(4	)
Proceeds from issuance of common units, net of offering costs		170			—			—			—			170
Excess purchase price over acquired unconsolidated affiliates		—			—			(36	)		—			(36	)
Net change in advances to predecessor from DCP Midstream, LLC		—			—			81			—			81
Distributions to common unitholders and general partner		(132	)		—			—			—			(132	)
Distributions to noncontrolling interests		—			—			(45	)		—			(45	)
Contributions from noncontrolling interests		—			—			18			—			18
Net cash provided by (used in) financing activities		38			95			18			—			151
Net change in cash and cash equivalents		—			2			(1	)		—			1
Cash and cash equivalents, beginning of year		—			2			7			(2	)		7
Cash and cash equivalents, end of year	$	—		$	4		$	6		$	(2	)	$	8

(a) The financial information as of December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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, 2012, 2011 and 2010

	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	)	$	(43	)	$	336		$	(1	)	$	205
INVESTING ACTIVITIES:
Capital expenditures		—			—			(185	)		—			(185	)
Acquisitions, net of cash acquired		—			—			(282	)		—			(282	)
Investments in unconsolidated affiliates		—			—			(2	)		—			(2	)
Return of investment from unconsolidated affiliate		—			—			1			—			1
Proceeds from sale of assets		—			—			4			—			4
Proceeds from sales of available-for-sale securities		—			10			—			—			10
Net cash provided by (used in) investing activities		—			10			(464	)		—			(454	)
FINANCING ACTIVITIES:
Proceeds from debt		—			868			—			—			868
Payments of debt		—			(833	)		(2	)		—			(835	)
Payment of deferred financing costs		—			(2	)		—			—			(2	)
Proceeds from issuance of common units, net of offering costs		189			—			—			—			189
Net change in advances to predecessor from DCP Midstream, LLC		—			—			151			—			151
Distributions to common unitholders and general partner		(102	)		—			—			—			(102	)
Distributions to noncontrolling interests		—			—			(26	)		—			(26	)
Contributions from noncontrolling interests		—			—			14			—			14
Contributions from DCP Midstream, LLC		—			—			1			—			1
Purchase of additional interest in a subsidiary		—			—			(4	)		—			(4	)
Net cash provided by (used in) financing activities		87			33			134			—			254
Net change in cash and cash equivalents		—			—			6			(1	)		5
Cash and cash equivalents, beginning of year		—			2			1			(1	)		2
Cash and cash equivalents, end of year	$	—		$	2		$	7		$	(2	)	$	7

(a) The financial information as of December 31, 2010 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge 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.

70

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2012, 2011 and 2010

21. Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2012, 2011 and 2010 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, 2012
Environmental	$	3	$	—	$	—	$	(1	)	$	2
Litigation		—		—		—		—			—
Other (a)		1		—		—		—			1
	$	4	$	—	$	—	$	(1	)	$	3
December 31, 2011
Environmental	$	3	$	—	$	—	$	—		$	3
Litigation		1		—		—		(1	)		—
Other (a)		—		1		—		—			1
	$	4	$	1	$	—	$	(1	)	$	4
December 31, 2010
Environmental	$	3	$	1	$	—	$	(1	)	$	3
Litigation		3		—		—		(2	)		1
Other (a)		—		—		1		(1	)		—
	$	6	$	1	$	1	$	(4	)	$	4

(a) Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in other long-term assets, other contingency liabilities, which are included in other current liabilities, and the recognition and re-measurement of the fair value of contingent consideration.

22. Subsequent Events

On January 28, 2013, we announced that the board of directors of DCP Midstream GP, LLC declared a quarterly distribution of $0.69 per unit, which was paid on February 14, 2013, to unitholders of record on February 7, 2013.

On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC and an $87 million fixed price commodity derivative hedge for a three-year period for aggregate consideration of $626 million, plus customary working capital and other purchase price adjustments. $490 million of the consideration was financed with the net proceeds from our 3.875% 10-year Senior Notes offering, $125 million was financed by the issuance at closing of an aggregate 2,789,739 of our common units to DCP Midstream, LLC and the remaining $11 million was paid with cash on hand. The $219 million excess purchase price over the carrying value of the acquired interest in the Eagle Ford system was recorded as a decrease in limited partners’ equity. We also reimbursed DCP Midstream, LLC $50 million for 46.67% of the capital spent to date by the Eagle Ford system for the construction of the Goliad plant, plus an incremental payment of $23 million as reimbursement for 46.67% of preformation capital expenditures. Prior to the acquisition of the additional interest in the Eagle Ford system, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method. The acquisition of the additional interest in the Eagle Ford system 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 80% interest in the Eagle Ford system for all periods presented, similar to the pooling method.

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