DCP Midstream (DCP-PC) 8-K Other Events

Exhibit 99.3

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets as of December 31, 2013 and 2012	3
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011	4
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	5
Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011	6
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	9
Notes to Consolidated Financial Statements	10

1

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, 2013 and 2012, 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, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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 Lucerne 1 Plant, LLC acquired on March 28, 2014, 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.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 26, 2014 (June 13, 2014 as to Notes 1, 3, 20, and 22)

2

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,   2013			December 31,   2012
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	12		$	2
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1 million and less than $1 million, respectively	130			107
Affiliates	212			132
Inventories	67			76
Unrealized gains on derivative instruments	79			49
Other	3			2
Total current assets	503			368
Property, plant and equipment, net	3,046			2,592
Goodwill	154			154
Intangible assets, net	129			137
Investments in unconsolidated affiliates	627			304
Unrealized gains on derivative instruments	87			70
Other long-term assets	21			20
Total assets	$	4,567		$	3,645
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	232		$	151
Affiliates	43			72
Short-term borrowings	335			—
Unrealized losses on derivative instruments	28			31
Capital spending accrual	24			44
Other	61			47
Total current liabilities	723			345
Long-term debt	1,590			1,620
Unrealized losses on derivative instruments	1			8
Other long-term liabilities	40			36
Total liabilities	2,354			2,009
Commitments and contingent liabilities
Equity:
Predecessor equity	40			399
Limited partners (89,045,139 and 61,346,058 common units issued and outstanding, respectively)	1,948			1,063
General partner	8			—
Accumulated other comprehensive loss	(11		)	(15		)
Total partners’ equity	1,985			1,447
Noncontrolling interests	228			189
Total equity	2,213			1,636
Total liabilities and equity	$	4,567		$	3,645

See accompanying notes to consolidated financial statements.

3

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2013			2012			2011
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	932		$	820		$	1,171
Sales of natural gas, propane, NGLs and condensate to affiliates	1,831			1,700			2,403
Transportation, processing and other	211			179			169
Transportation, processing and other to affiliates	60			55			39
(Losses) gains from commodity derivative activity, net	(5		)	17			7
Gains from commodity derivative activity, net — affiliates	22			53			1
Total operating revenues	3,051			2,824			3,790
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,159			1,807			2,445
Purchases of natural gas, propane and NGLs from affiliates	267			408			710
Operating and maintenance expense	215			197			192
Depreciation and amortization expense	95			91			135
General and administrative expense	17			17			19
General and administrative expense — affiliates	46			58			57
Other expense (income)	8			—			(1		)
Total operating costs and expenses	2,807			2,578			3,557
Operating income	244			246			233
Interest expense	(52		)	(42		)	(34		)
Earnings from unconsolidated affiliates	33			26			23
Income before income taxes	225			230			222
Income tax expense	(8		)	(1		)	(1		)
Net income	217			229			221
Net income attributable to noncontrolling interests	(17		)	(13		)	(30		)
Net income attributable to partners	200			216			191
Net income attributable to predecessor operations	(25		)	(51		)	(91		)
General partner’s interest in net income	(70		)	(41		)	(25		)
Net income allocable to limited partners	$	105		$	124		$	75
Net income per limited partner unit — basic	$	1.34		$	2.28		$	1.73
Net income per limited partner unit — diluted	$	1.34		$	2.28		$	1.72
Weighted-average limited partner units outstanding — basic	78.4			54.5			43.5
Weighted-average limited partner units outstanding — diluted	78.4			54.5			43.6

See accompanying notes to consolidated financial statements.

4

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2013			2012			2011
	(Millions)
Net income	$	217		$	229		$	221
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	4			10			21
Net unrealized losses on cash flow hedges	—			—			(13		)
Net unrealized losses on cash flow hedges - predecessor operations	—			(1		)	(2		)
Total other comprehensive income	4			9			6
Total comprehensive income	221			238			227
Total comprehensive income attributable to noncontrolling interests	(17		)	(13		)	(30		)
Total comprehensive income attributable to partners	$	204		$	225		$	197

See accompanying notes to consolidated financial statements.

5

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Partners’ Equity
	Predecessor Equity			Limited Partners			General Partner			Accumulated Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2013	$	399		$	1,063		$	—		$	(15	)	$	189		$	1,636
Net income	25			105			70			—			17			217
Other comprehensive income	—			—			—			4			—			4
Net change in parent advances	11			—			—			—			—			11
Acquisition of an additional 46.67% interest in the Eagle Ford system	(395		)	—			—			—			—			(395		)
Issuance of units for the Eagle Ford system	—			125			—			—			—			125
Excess purchase price over carrying value of acquired investment of 33.33% interest in the Eagle Ford system and NGL hedge	—			(7		)	—			—			—			(7		)
Excess purchase price over carrying value of acquired additional 46.67% interest in the Eagle Ford system and commodity hedge	—			(203		)	—			—			—			(203		)
Issuance of 24,897,977 common units	—			1,082			—			—			—			1,082
Distributions to limited partners and general partner	—			(215		)	(62		)	—			—			(277		)
Distributions to noncontrolling interests	—			—			—			—			(24		)	(24		)
Contributions from noncontrolling interests	—			—			—			—			46			46
Contributions from DCP Midstream, LLC	—			1			—			—			—			1
Distributions to DCP Midstream, LLC	—			(3		)	—			—			—			(3		)
Balance, December 31, 2013	$	40		$	1,948		$	8		$	(11	)	$	228		$	2,213

See accompanying notes to consolidated financial statements.

6

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Partners’ Equity
	Predecessor Equity			Limited  Partners			General  Partner			Accumulated  Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2012	$	671		$	654		$	(5	)	$	(21	)	$	306		$	1,605
Net income	51			124			41			—			13			229
Other comprehensive (loss) income	(1		)	—			—			10			—			9
Net change in advances to predecessor from DCP Midstream, LLC	181			—			—			—			40			221
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 limited partners 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	$	399		$	1,063		$	—		$	(15	)	$	189		$	1,636

See accompanying notes to consolidated financial statements.

7

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Partners’ Equity
	Predecessor Equity			Limited  Partners			General  Partner			Accumulated  Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2011	$	654		$	552		$	(6	)	$	(28	)	$	288		$	1,460
Net income	91			75			25			—			30			221
Other comprehensive (loss) income	(2		)	—			—			8			—			6
Net change in advances to predecessor from DCP Midstream, LLC	42			—			—			—			15			57
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 limited partners and general partner	—			(108		)	(24		)	—			—			(132		)
Distributions to noncontrolling interests	—			—			—			—			(45		)	(45		)
Contributions from noncontrolling interests	—			—			—			—			18			18
Balance, December 31, 2011	$	671		$	654		$	(5	)	$	(21	)	$	306		$	1,605

See accompanying notes to consolidated financial statements.

8

DCP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(Millions)
OPERATING ACTIVITIES:
Net income	$	217		$	229		$	221
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	95			91			135
Earnings from unconsolidated affiliates	(33		)	(26		)	(23		)
Distributions from unconsolidated affiliates	39			24			25
Net unrealized losses (gains) on derivative instruments	36			(21		)	(40		)
Deferred income taxes, net	5			—			(29		)
Other, net	14			3			5
Change in operating assets and liabilities, which (used) provided cash, net of effects of acquisitions:
Accounts receivable	(89		)	(11		)	34
Inventories	9			14			(14		)
Accounts payable	51			(194		)	106
Accrued interest	5			5			—
Other current assets and liabilities	(2		)	(4		)	2
Other long-term assets and liabilities	(2		)	(8		)	(5		)
Net cash provided by operating activities	345			102			417
INVESTING ACTIVITIES:
Capital expenditures	(363		)	(484		)	(385		)
Acquisitions, net of cash acquired	(696		)	(433		)	(38		)
Acquisition of unconsolidated affiliates	(86		)	(312		)	(114		)
Investments in unconsolidated affiliates	(242		)	(158		)	(8		)
Return of investment from unconsolidated affiliate	—			1			2
Proceeds from sales of assets	—			2			5
Net cash used in investing activities	(1,387		)	(1,384		)	(538		)
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,957			2,665			1,524
Payments of long-term debt	(1,988		)	(1,792		)	(1,425		)
Proceeds from issuance of commercial paper	335			—			—
Payments of deferred financing costs	(4		)	(8		)	(4		)
Excess purchase price over acquired interests and commodity hedges	(85		)	(225		)	(36		)
Proceeds from issuance of common units, net of offering costs	1,083			455			170
Net change in advances to predecessor from DCP Midstream, LLC	11			336			52
Distributions to limited partners and general partner	(277		)	(181		)	(132		)
Distributions to noncontrolling interests	(24		)	(9		)	(45		)
Contributions from noncontrolling interests	46			25			18
Distributions to DCP Midstream, LLC	(3		)	—			—
Contributions from DCP Midstream, LLC	1			10			—
Net cash provided by financing activities	1,052			1,276			122
Net change in cash and cash equivalents	10			(6		)	1
Cash and cash equivalents, beginning of year	2			8			7
Cash and cash equivalents, end of year	$	12		$	2		$	8

See accompanying notes to consolidated financial statements.

9

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2013, 2012 and 2011

1. Description of Business and Basis of Presentation

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

We are a Delaware limited partnership that was formed in August 2005. Our partnership includes: our natural gas services segment (which includes our 80% interest in the Eagle Ford system, our 100% owned Eagle Plant; our East Texas system; our Southeast Texas system; our Michigan system; our Northern Louisiana system; our Southern Oklahoma system; our Wyoming system; a 75% interest in Collbran Valley Gas Gathering, LLC, or Collbran or our Piceance system; our 40% interest in Discovery Producer Services LLC, or Discovery; and our DJ Basin system, consisting of our O'Connor and Lucerne 1 plants), our NGL logistics segment (which includes the NGL storage facility in Michigan, our 12.5% interest in the Mont Belvieu Enterprise fractionator, our 20% interest in the Mont Belvieu 1 fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ Basin NGL fractionators, the Seabreeze and Wilbreeze intrastate NGL pipelines, our 33.33% interest in the Front Range interstate NGL pipeline, and our 10% interest in the Texas Express intrastate NGL pipeline), and our wholesale propane logistics segment (which includes six rail terminals, two marine terminals and one pipeline terminal).

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 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. 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 23% 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 a 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, 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, and our 100% interest in DCP Lucerne 1 Plant, LLC, a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant, which we acquired from DCP Midstream, LLC in March 2014. 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 in March 2013, 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 commodity derivative hedge instruments associated with the storage business, our 80% interest in the Eagle Ford system and our Lucerne 1 plant 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.

10

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 and temporary investments of cash in short-term money market securities 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 at the reporting unit level during 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, supplemented by a market approach 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.

Intangible assets consist 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, including intangible 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.

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.

11

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 accretes 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:

Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Cash Flow Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item
Fair Value Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item
Normal Purchases or Normal Sales	Accrual method (b)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale
Other Non-Trading Derivative Activity	Mark-to-market method (c)	Net basis in gains and losses from commodity derivative activity

______________

(a) 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.

(b) 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.

(c) 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.

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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 change in fair value of the effective portion 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 line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.

Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.

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

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 and recovering and selling condensate. 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, NGLs and condensate, or by receiving fees. We also generate revenue from transporting, storing and selling propane.

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 fractionating, storing and transporting NGLs. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain 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

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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 the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. 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.

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 and 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, 2013, 2012 and 2011. We 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 included in the consolidated balance sheets as other current liabilities amounted to $1 million, and other long-term liabilities amounted to $1 million at both December 31, 2013 and 2012.

Equity-Based Compensation - Equity classified share-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 share-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.

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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 of 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.

3. Acquisitions

On March 28, 2014, we acquired the Lucerne 1 Plant from DCP Midstream, LLC and its affiliates. The Lucerne 1 plant, along with our O'Connor plant, comprises our DJ Basin system. In conjunction with our acquisition of the Lucerne 1 plant, we entered into a long-term fee-based processing agreement with DCP Midstream, LLC pursuant to which DCP Midstream, LLC agreed to pay us (i) a fixed demand charge of 75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for DCP Midstream, LLC at the Lucerne 1 plant. The acquisition of the Lucerne 1 plant 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 the Lucerne 1 plant for all periods presented, similar to the pooling method. Also in March 2014, DCP Midstream, LLC and its affiliates contributed or sold to us (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; and (iii) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under construction, or the Lucerne 2 plant. The March 2014 transactions are discussed in Note 22. "Subsequent Events".

On August 5, 2013, we entered into a purchase and sale agreement with DCP Midstream, LP, or Midstream LP, a 100% owned subsidiary of DCP Midstream, LLC, pursuant to which the Partnership acquired from Midstream LP all of the membership interests in DCP LaSalle Plant LLC, or the LaSalle Transaction, for consideration of $209 million, subject to certain customary purchase price adjustments. The LaSalle Transaction was financed at closing using borrowings under our revolving credit facility.

DCP LaSalle Plant LLC owns the O'Connor plant, a cryogenic natural gas processing plant in Weld County, Colorado with initial capacity of 110 MMcf/d. Prior to the start of commercial operations in October 2013, the O'Connor plant was known as the LaSalle plant. The LaSalle Transaction represents a transfer of assets between entities under common control. The results of the O'Connor plant are included prospectively from the date of contribution in our Natural Gas Services segment. As of February 2014, the O'Connor plant expansion to 160 MMcf/d is mechanically complete.

On August 5, 2013, we entered into a purchase and sale agreement with Midstream LP pursuant to which the Partnership acquired from Midstream LP all of the membership interests in DCP Midstream Front Range LLC, or Front Range, for consideration of $86 million, subject to certain customary purchase price adjustments, or the Front Range Transaction. The Front Range Transaction was financed at closing using borrowings under our revolving credit facility.

Front Range owns a 33.33% equity interest in Front Range Pipeline LLC, a joint venture with affiliates of Enterprise Products Partners L.P., or Enterprise, and Anadarko Petroleum Corporation. The joint venture was formed to construct a new raw NGL mix pipeline that originates in the DJ Basin and extends approximately 435 miles to Skellytown, Texas, or the Front Range pipeline. With connections to the Mid-America pipeline, and to the Texas Express pipeline, in which the Partnership owns a 10% interest, the Front Range pipeline provides takeaway capacity and market access to the Gulf Coast for the

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expanding production of NGLs in the DJ Basin. The Front Range pipeline connects to the O'Connor plant as well as third party and DCP Midstream, LLC plants in the DJ Basin. The initial capacity of the Front Range pipeline is expected to be 150 MBbls/d, which could be expanded to 230 MBbls/d with the installation of additional pump stations. Enterprise is the operator of the pipeline, which was placed into service in February 2014. The Front Range pipeline currently has transportation agreements in place with affiliates of DCP Midstream, LLC and others. The transportation agreements provide for ship-or-pay arrangements for the first 10 years for a minimum volume specified in the agreement, with the last five years under plant dedication arrangements. The Front Range transaction represents a transfer of assets between entities under common control. The results of Front Range are included prospectively from the date of contribution in our NGL Logistics segment.

On March 28, 2013, we acquired an additional 46.67% interest in DCP SC Texas GP, or 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. 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 $203 million excess purchase price over the carrying value of the acquired interest in the Eagle Ford system, as adjusted for customary working capital and other purchase price adjustments, was recorded as a decrease in limited partners’ equity. 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 Eagle Ford system acquisition 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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The assets and liabilities of our Lucerne 1 plant are included in the consolidated balance sheet as of December 31, 2013. The following table presents the previously reported December 31, 2013 consolidated balance sheet, adjusted for the acquisition of our Lucerne 1 plant from DCP Midstream, LLC:

As of December 31, 2013

	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
ASSETS
Current assets:
Cash and cash equivalents	$	12		$	—	$	12
Accounts receivable	342			—		342
Inventories	67			—		67
Other	82			—		82
Total current assets	503			—		503
Property, plant and equipment, net	3,005			41		3,046
Goodwill and intangible assets, net	283			—		283
Investments in unconsolidated affiliates	627			—		627
Other non-current assets	108			—		108
Total assets	$	4,526		$	41	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	722		$	1	$	723
Long-term debt	1,590			—		1,590
Other long-term liabilities	41			—		41
Total liabilities	2,353			1		2,354
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity	1,956			40		1,996
Accumulated other comprehensive loss	(11		)	—		(11		)
Total partners’ equity	1,945			40		1,985
Noncontrolling interests	228			—		228
Total equity	2,173			40		2,213
Total liabilities and equity	$	4,526		$	41	$	4,567

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The assets and liabilities of our Lucerne 1 plant 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 our Lucerne 1 plant from DCP Midstream, LLC:

As of December 31, 2012

	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	2		$	—	$	2
Accounts receivable	239			—		239
Inventories	76			—		76
Other	51			—		51
Total current assets	368			—		368
Property, plant and equipment, net	2,550			42		2,592
Goodwill and intangible assets, net	291			—		291
Investments in unconsolidated affiliates	304			—		304
Other non-current assets	90			—		90
Total assets	$	3,603		$	42	$	3,645
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	345		$	—	$	345
Long-term debt	1,620			—		1,620
Other long-term liabilities	44			—		44
Total liabilities	2,009			—		2,009
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity	1,420			42		1,462
Accumulated other comprehensive loss	(15		)	—		(15		)
Total partners’ equity	1,405			42		1,447
Noncontrolling interests	189			—		189
Total equity	1,594			42		1,636
Total liabilities and equity	$	3,603		$	42	$	3,645

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The results of our Lucerne 1 plant are included in the consolidated statement of operations for the year ended December 31, 2013. The following table presents the previously reported consolidated statement of operations for the year ended December 31, 2013, adjusted for the acquisition of our Lucerne 1 plant from DCP Midstream, LLC:

Year ended December 31, 2013

		DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate		$	2,695		$	68	$	2,763
Transportation, processing and other		268			3		271
Gains from commodity derivative activity, net		17			—		17
Total operating revenues		2,980			71		3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs		2,381			45		2,426
Operating and maintenance expense		211			4		215
Depreciation and amortization expense		93			2		95
General and administrative expense		62			1		63
Other income		8			—		8
Total operating costs and expenses		2,755			52		2,807
Operating income		225			19		244
Interest expense		(52		)	—		(52		)
Earnings from unconsolidated affiliates		33			—		33
Income before income taxes		206			19		225
Income tax expense		(8		)	—		(8		)
Net income		198			19		217
Net income attributable to noncontrolling interests		(17		)	—		(17		)
Net income attributable to partners		$	181		$	19	$	200

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The results of our Lucerne 1 plant are included in the consolidated statement of operations for the year ended December 31, 2012. The following table presents the previously reported consolidated statement of operations for the year endedDecember 31, 2012, adjusted for the acquisition of our Lucerne 1 plant from DCP Midstream, LLC:

Year Ended December 31, 2012

	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	2,459		$	61	$	2,520
Transportation, processing and other	232			2		234
Losses from commodity derivative activity, net	70			—		70
Total operating revenues	2,761			63		2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,177			38		2,215
Operating and maintenance expense	193			4		197
Depreciation and amortization expense	89			2		91
General and administrative expense	74			1		75
Total operating costs and expenses	2,533			45		2,578
Operating income	228			18		246
Interest expense	(42		)	—		(42		)
Earnings from unconsolidated affiliates	26			—		26
Income before income taxes	212			18		230
Income tax expense	(1		)	—		(1		)
Net income	211			18		229
Net income attributable to noncontrolling interests	(13		)	—		(13		)
Net income attributable to partners	$	198		$	18	$	216

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Year Ended December 31, 2011

The results of our Lucerne 1 plant are included in the consolidated statement of operations for the year endedDecember 31, 2011. The following table presents the previously reported consolidated statement of operations for the year endedDecember 31, 2011 adjusted for the acquisition of our Lucerne 1 plant from DCP Midstream, LLC:

	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	3,487		$	87	$	3,574
Transportation, processing and other	205			3		208
Gains from commodity derivative activity, net	8			—		8
Total operating revenues	3,700			90		3,790
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	3,100			55		3,155
Operating and maintenance expense	188			4		192
Depreciation and amortization expense	133			2		135
General and administrative expense	75			1		76
Other income	(1		)	—		(1		)
Total operating costs and expenses	3,495			62		3,557
Operating income	205			28		233
Interest expense	(34		)	—		(34		)
Earnings from unconsolidated affiliates	23			—		23
Income before income taxes	194			28		222
Income tax expense	(1		)	—		(1		)
Net income	193			28		221
Net income attributable to noncontrolling interests	(30		)	—		(30		)
Net income attributable to partners	$	163		$	28	$	191

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 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 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 were recorded at their estimated fair value and are included in other current liabilities, other long-term liabilities, and accounts receivable as of the acquisition date. 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:

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	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 for the year ended December 31, 2012.

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	$	2,824		$	27	$	2,851
Net income attributable to partners	$	216		$	2	$	218
Less:
Net income attributable to predecessor operations	(51		)	—		(51		)
General partner’s interest in net income	(41		)	—		(41		)
Net income allocable to limited partners	$	124		$	2	$	126
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.

	Year Ended December 31, 2011
	DCP Midstream Partners, LP			Acquisition of Crossroads		DCP Midstream Partners, LP Pro Forma
	(Millions)
Total operating revenues	$	3,790		$	114	$	3,904
Net income attributable to partners	$	191		$	4	$	195
Less:
Net income attributable to predecessor operations	(91		)	—		(91		)
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

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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.

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, which replaced the Omnibus Agreement on February 14, 2013, 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 Services 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. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. Pursuant to the Services Agreement, we will reimburse DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.

The Services Agreement fee is subject to adjustment based on the scope of general and administrative services performed by DCP Midstream, LLC.

The following is a summary of the fees we incurred under the Services and Omnibus Agreements, as well as other fees paid to DCP Midstream, LLC:

	Year Ended   December 31,
	2013		2012		2011
	(Millions)
Services/Omnibus Agreement	$	29	$	26	$	10
Other fees — DCP Midstream, LLC	17		32		47
Total — DCP Midstream, LLC	$	46	$	58	$	57

In addition to the fees paid pursuant to the Services and Omnibus Agreements, we incurred allocated expenses, including insurance and internal audit fees with DCP Midstream, LLC of $2 million for the year ended December 31, 2013 and $1 million for each of the years ended December 31, 2012 and 2011, respectively. The Lucerne 1 plant incurred $1 million in general and administrative expenses directly from DCP Midstream, LLC for each of the years ended December 31, 2013, 2012 and 2011. The Eagle Ford system incurred $14 million for the year ended December 31, 2013 and $27 million for each of the years ended December 31, 2012 and 2011, respectively, in general and administrative expenses directly from DCP Midstream, LLC. For the years ended December 31, 2012 and 2011, Southeast Texas incurred $3 million and $10 million in general and administrative expenses directly from DCP Midstream, LLC, before the addition of Southeast Texas to the Omnibus Agreement in March 2012. During the year ended December 31, 2011, East Texas incurred $8 million in general and administrative expenses directly from DCP Midstream, LLC.

Competition

None of DCP Midstream, LLC, or any of its affiliates, including Phillips 66 and Spectra Energy, is restricted, under either the partnership agreement or the Services Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Phillips 66 and Spectra Energy, 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.

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Other Agreements and Transactions with DCP Midstream, LLC

DCP Midstream, LLC was a significant customer during the years ended December 31, 2013, 2012 and 2011. 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, we have an agreement 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 and NGLs 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 upon 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.

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 $1 million, $5 million and $18 million for the years ended December 31, 2013, 2012, and 2011 respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of $5 million for the year ended December 31, 2012. We made a distribution to DCP Midstream, LLC related to capital projects at Southeast Texas of $3 million for the year ended December 31, 2013.

In conjunction with our acquisition of the O'Connor plant, we entered into a 15-year fee-based processing agreement with an affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of 75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor plant. Under this agreement, we received fees of $6 million during the year ended December 31, 2013, which are included in transportation, processing and other to affiliates in the consolidated statements of operations.

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 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.

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 sales of natural gas, propane, NGLs and condensate, with $5 million representing DCP Midstream, LLC’s portion recorded in net income attributable to noncontrolling interests, in the consolidated statement of operations.

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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.

The Texas Express Pipeline has in place a long-term, fee-based, ship-or-pay transportation agreement with DCP Midstream, LLC of 20 MBbls/d.

The Wattenberg pipeline has in place 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 $1 million and less than $1 million during the years ended December 31, 2013 and 2012, respectively, which are included in operating and maintenance expense in the consolidated statements of operations.

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.

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Year Ended   December 31,
	2013		2012		2011
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	1,830	$	1,691	$	2,346
Transportation, processing and other	$	60	$	52	$	30
Purchases of natural gas, propane and NGLs	$	204	$	173	$	244
Gains from commodity derivative activity, net	$	22	$	53	$	1
Operating and maintenance expense	$	1	$	1	$	1
General and administrative expense	$	46	$	58	$	57
Phillips 66:
Sales of natural gas, propane, NGLs and condensate	$	1	$	—	$	—
ConocoPhillips (a):
Sales of natural gas, propane, NGLs and condensate	$	—	$	9	$	57
Transportation, processing and other	$	—	$	3	$	9
Purchases of natural gas, propane and NGLs	$	—	$	67	$	139
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	63	$	166	$	321
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	—	$	2	$	6

(a) In connection with Phillips 66's separation from ConocoPhillips, 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.

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We had balances with affiliates as follows:

	December 31,   2013		December 31,   2012
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	211	$	132
Accounts payable	$	37	$	66
Unrealized gains on derivative instruments — current	$	79	$	48
Unrealized gains on derivative instruments — long-term	$	81	$	64
Unrealized losses on derivative instruments — current	$	18	$	(11	)
Unrealized losses on derivative instruments — long-term	$	1	$	—
Spectra Energy:
Accounts receivable	$	1	$	—
Accounts payable	$	6	$	5
Unconsolidated affiliates:
Accounts payable	$	—	$	1

5. Inventories

Inventories were as follows:

	December 31,   2013		December 31,   2012
	(Millions)
Natural gas	$	38	$	22
NGLs	29		54
Total inventories	$	67	$	76

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 $4 million and $19 million in lower of cost or market adjustments during the years ended December 31, 2013 and 2012, respectively.

6. Property, Plant and Equipment

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

	Depreciable Life	December 31,   2013			December 31,   2012
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,205		$	1,921
Processing, storage, and terminal facilities	35 — 60 Years	1,645			1,154
Other	3 —  30 Years	49			32
Construction work in progress		310			561
Property, plant and equipment		4,209			3,668
Accumulated depreciation		(1,163		)	(1,076		)
Property, plant and equipment, net		$	3,046		$	2,592

Interest capitalized on construction projects in 2013, 2012 and 2011 was $11 million, $7 million and $2 million, respectively.

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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 producers' estimated remaining economically recoverable reserves resulting from the widespread application of techniques, such as hydraulic fracturing and horizontal drilling, 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.

Depreciation expense was $87 million, $83 million, and $127 million for the years ended December 31, 2013, 2012, and 2011, respectively.

During the year ended December 31, 2013, we discontinued certain construction projects and wrote off approximately $8 million in construction work in progress to other expense in the consolidated statements of operations.

Asset Retirement Obligations - As of December 31, 2013 and 2012, we had asset retirement obligations of $24 million and $23 million, respectively, included in other long-term liabilities in the consolidated balance sheets. Accretion expense was $1 million for each of the years ended December 31, 2013 and 2011 and accretion benefit was less than $1 million for the year ended December 31, 2012.

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 value of goodwill as of December 31, 2013 and December 31, 2012 was $154 million for each of the periods, consisting of $82 million for our Natural Gas Services segment, $35 million for our NGL Logistics segment and $37 million 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 fair value of goodwill substantially exceeded its carrying value and that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We primarily used a discounted cash flow analysis, supplemented by a market approach 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:

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	December 31,
	2013			2012
	(Millions)
Gross carrying amount	$	164		$	164
Accumulated amortization	(35		)	(27		)
Intangible assets, net	$	129		$	137

For each of the years ended December 31, 2013, 2012, and 2011, we recorded amortization expense of $8 million. As of December 31, 2013, the remaining amortization periods ranged from approximately 8 years to 22 years, with a weighted-average remaining period of approximately 17 years.

Estimated future amortization for these intangible assets is as follows:

Estimated Future Amortization
(Millions)
2014	$	8
2015	8
2016	8
2017	8
2018	8
Thereafter	89
Total	$	129

8. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	December 31,   2013		December 31,   2012
		(Millions)
Discovery Producer Services LLC	40%	$	348	$	223
Front Range Pipeline LLC	33.33%	134		—
Texas Express Pipeline	10%	96		41
Mont Belvieu Enterprise Fractionator	12.5%	26		19
Mont Belvieu 1 Fractionator	20%	16		14
CrossPoint Pipeline, LLC	50%	6		6
Other	Various	1		1
Total investments in unconsolidated affiliates		$	627	$	304

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $28 million and $30 million at December 31, 2013 and December 31, 2012, respectively, which is associated with, and is being amortized over, the life of the underlying long-lived assets of Discovery.

There was an excess of the carrying amount of the investment over the underlying equity of Front Range of $4 million at December 31, 2013, which is associated with interest capitalized during the construction of the pipeline and will be amortized over the life of the underlying long-lived assets of Front Range pipeline.

There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million and less than $1 million at December 31, 2013 and December 31, 2012, respectively, which is associated with interest capitalized during the construction of the pipeline and is being amortized over the life of the underlying long-lived assets of Texas Express.

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There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu 1 of $5 million and $6 million at December 31, 2013 and December 31, 2012, respectively, 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,
	2013			2012		2011
	(Millions)
Mont Belvieu 1 Fractionator	$	19		$	6	$	—
Mont Belvieu Enterprise Fractionator	14			5		—
Discovery Producer Services LLC	1			15		23
Texas Express	(1		)	—		—
Total earnings from unconsolidated affiliates	$	33		$	26	$	23

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:

	Year Ended December 31,
	2013		2012		2011
	(Millions)
Statements of operations:
Operating revenue	$	484	$	293	$	213
Operating expenses	$	298	$	190	$	163
Net income	$	186	$	103	$	50

	December 31,   2013			December 31,   2012
	(Millions)
Balance sheets:
Current assets	$	182		$	129
Long-term assets	2,678			1,288
Current liabilities	(276		)	(75		)
Long-term liabilities	(37		)	(43		)
Net assets	$	2,547		$	1,299

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

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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 positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

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

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

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

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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, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

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

Interest Rate Derivative Assets and Liabilities

We use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our existing floating rate debt for fixed-rate debt. 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 to perform impairment tests as required on our property, plant and equipment; goodwill; and intangible assets. Assets and liabilities acquired in third party 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.

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The following table presents the financial instruments carried at fair value as of December 31, 2013 and December 31, 2012, by consolidated balance sheet caption and by valuation hierarchy, as described above:

	December 31, 2013										December 31, 2012
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets (a):
Commodity derivatives	$	—	$	14		$	65	$	79		$	—	$	9		$	40		$	49
Short-term investments (b)	$	9	$	—		$	—	$	9		$	2	$	—		$	—		$	2
Long-term assets (c):
Commodity derivatives	$	—	$	12		$	75	$	87		$	—	$	5		$	65		$	70
Current liabilities (d):
Commodity derivatives	$	—	$	(26	)	$	—	$	(26	)	$	—	$	(26	)	$	(1	)	$	(27	)
Interest rate derivatives	$	—	$	(2	)	$	—	$	(2	)	$	—	$	(4	)	$	—		$	(4	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(1	)	$	—	$	(1	)	$	—	$	(6	)	$	—		$	(6	)
Interest rate derivatives	$	—	$	—		$	—	$	—		$	—	$	(2	)	$	—		$	(2	)

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

(b) Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.

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

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

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

Changes in Levels 1 and 2 Fair Value Measurements

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 years ended December 31, 2013 and 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. 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.

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.

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	Commodity Derivative Instruments
	Current Assets			Long- Term Assets			Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2013 (a):
Beginning balance	$	40		$	65		$	(1	)	$	—
Net realized and unrealized gains (losses) included in earnings (c)	42			(50		)	—			—
Transfers into Level 3 (b)	—			—			—
Transfers out of Level 3 (b)	(1		)	(2		)	1			—
Settlements	(40		)	—			—			—
Purchases	24			62			—			—
Ending balance	$	65		$	75		$	—		$	—
Net unrealized gains (losses) still held included in earnings (c)	$	41		$	(50	)	$	—		$	—
Year ended December 31, 2012 (a):
Beginning balance	$	1		$	1		$	(1	)	$	—
Net realized and unrealized gains included in earnings (c)	14			2			—			—
Transfers into Level 3 (b)	—			—			—			—
Transfers out of Level 3 (b)	—			—			—			—
Settlements	(2		)	—			—			—
Purchases	27			62			—			—
Ending balance	$	40		$	65		$	(1	)	$	—
Net unrealized gains still held included in earnings (c)	$	13		$	2		$	—		$	—

(a) There were no issuances or sales of derivatives for the years ended December 31, 2013 and 2012.

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

(c) Represents the amount of total gains or losses for the year, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

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.

	December 31, 2013
Product Group	Fair Value		Forward Curve Range
	(Millions)
Assets
NGLs	$	140	$0.27-$2.11	Per gallon

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

33

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 specific 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.

The fair value of accounts receivable, accounts payable and short-term borrowings 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.

The carrying value of outstanding balances under our Credit Agreement was $525 million as of December 31, 2012, which approximated fair value.

The carrying and fair values of the 3.875% Senior Notes were $494 million and $461 million, respectively, as of December 31, 2013.

The carrying and fair values of the 2.50% Senior Notes was $497 million and $500 million as of December 31, 2013. The carrying value as of December 31, 2012 was $500 million, which approximated fair value.

The carrying and fair values of the 4.95% Senior Notes was $349 million and $354 million, respectively as of December 31, 2013, and $350 million and $374 million, respectively, as of December 31, 2012.

The carrying and fair values of the 3.25% Senior Notes were $250 million and $258 million, respectively, as of December 31, 2013, and $250 million and $259 million, respectively, as of December 31, 2012.

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 Senior Notes based on quotes obtained from bond dealers. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy.

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10. Debt

	December 31,   2013			December 31,   2012
	(Millions)
Commercial Paper
Short-term borrowings, weighted-average interest rate of 1.14%	$	335		$	—
Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.47%, as of December 31, 2012, due November 10, 2016 (a)	—			525
Debt Securities
Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			—
Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015	250			250
Unamortized discount	(10		)	(5		)
Total debt	1,925			1,620
Short-term borrowings	(335		)	—
Total long-term debt	$	1,590		$	1,620

(a) $150 million was swapped to a fixed rate obligation with 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.

Commercial Paper Program

In October 2013, we entered into a commercial paper program, or the Commercial Paper Program, under which we may issue unsecured commercial paper notes, or the Notes. The Commercial Paper Program serves as an alternative source of funding and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper Program may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of Notes outstanding, combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the aggregate. Amounts undrawn under our revolving credit facility are available to repay the Notes, if necessary. The maturities of the Notes will vary, but may not exceed 397 days from the date of issue. The Notes will be sold under customary terms in the commercial paper market and may be issued at a discount from par, or, alternatively, may be sold at par and bear varying interest rates on a fixed or floating basis. The proceeds of the issuances of the Notes are expected to be used for capital expenditures and other general partnership purposes. As of December 31, 2013, we had $335 million of commercial paper outstanding, which is included in short-term borrowings in our consolidated balance sheets.

Credit Agreement

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

At December 31, 2013 and 2012, we had $1 million of letters of credit issued and outstanding under the Credit Agreement. As of December 31, 2013, the unused capacity under the Credit Agreement was $664 million, net of amounts outstanding under our Commercial Paper Program and letters of credit, which was available for general working capital purposes.

Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the November 10, 2016 maturity date.

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We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of London Interbank Offered Rate, or LIBOR, borrowings. 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 March 14, 2013, we issued $500 million of 3.875%10-year Senior Notes due March 15, 2023. We received proceeds of $490 million, net of underwriters’ fees, related expenses and unamortized discounts of $10 million, which we used to fund a portion of the purchase price for the acquisition of an additional 46.67% interest in the Eagle Ford system. Interest on the notes will be paid semi-annually on March 15 and September 15 of each year, commencing September 15, 2013. The notes will mature on March 15, 2023, unless redeemed prior to maturity.

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.

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.

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 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. 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.

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

	Debt Maturities
	(Millions)
2014	$	—
2015	250
2016	—
2017	500
2018	—
Thereafter	850
	1,600
Unamortized discount	(10		)
Total	$	1,590

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 either physical or 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 composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following 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 significant portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2017 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. The relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL hedges from 2014 through 2017 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.

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

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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 — 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. During 2011, Southeast Texas commenced an expansion project to build an additional storage cavern. To mitigate risk associated with the forecasted purchase of natural gas, we executed a series of derivative financial instruments, which were designated as cash flow hedges. During the second half of 2013, Southeast Texas purchased base gas to bring the storage cavern to operation. The balance in accumulated other comprehensive income, or AOCI, of these cash flow hedges was in a loss position of $3 million as of December 31, 2013. While the cash paid upon settlement of these hedges economically fixed the cash required to purchase the base gas, the deferred loss will remain in AOCI until the cavern is emptied and the base gas is sold.

Interest Rate Risk

At December 31, 2013, we had interest rate swap agreements extending through June 2014 with notional values totaling $150 million, which are accounted for under the mark-to-market method of accounting and 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. Prior to August of 2013, these interest rate swaps were designated as cash flow hedges whereby the effective portions of changes in fair value were recognized in AOCI in the consolidated balance sheets. The deferred loss in AOCI of $3 million, at the time of de-designation, will be reclassified into earnings as the hedged transactions impact earnings.

In March 2012, we settled $195 million of our forward-starting interest rate swap agreements for $7 million. The net deferred losses in AOCI of $5 million, at the settlement date, 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.

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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, 2013, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

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

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2013, we had $8 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2013, 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, 2013, 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 $6 million.

As of December 31, 2013, we had $150 million of interest rate swap instruments that were in a net liability position of $2 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.

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:

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	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
	December 31, 2013									December 31, 2012
Assets:
Commodity derivatives	$	166		$	(13	)	$	153		$	119		$	(10	)	$	109
Interest rate derivatives	$	—		$	—		$	—		$	—		$	—		$	—
Liabilities:
Commodity derivatives	$	(27	)	$	13		$	(14	)	$	(33	)	$	10		$	(23	)
Interest rate derivatives	$	(2	)	$	—		$	(2	)	$	(6	)	$	—		$	(6	)

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

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Summarized Derivative Information

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,   2013		December 31,   2012		Balance Sheet Line Item	December 31,   2013			December 31,   2012
	(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	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments — current	$	—	$	—	Unrealized losses on derivative instruments — current	$	—		$	(4	)
Unrealized gains on derivative instruments — long-term	—		—		Unrealized losses on derivative instruments — long-term	—			(2		)
	$	—	$	—		$	—		$	(6	)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	79	$	49	Unrealized losses on derivative instruments — current	$	(26	)	$	(24	)
Unrealized gains on derivative instruments — long-term	87		70		Unrealized losses on derivative instruments — long-term	(1		)	(6		)
	$	166	$	119		$	(27	)	$	(30	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments — current	$	—	$	—	Unrealized losses on derivative instruments — current	$	(2	)	$	—
Unrealized gains on derivative instruments — long-term	—		—		Unrealized losses on derivative instruments — long-term	—			—
	$	—	$	—		$	(2	)	$	—

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The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2013:

	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(10	)		$	(6	)	$	1	$	(15	)
Losses reclassified from AOCI to earnings — effective portion	4			(b)	—			—		4
Net deferred (losses) gains in AOCI (ending balance)	$	(6	)		$	(6	)	$	1	$	(11	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(2	)		$	—		$	—	$	(2	)

(a) Relates to Discovery, our unconsolidated affiliate.

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

For the year ended December 31, 2013, less than $1 million of derivative losses attributable to the ineffective portion was recognized in gains or losses from commodity derivative activity, net and interest expense in our consolidated statements of operations. For the year ended December 31, 2013, $1 million of derivative gains were reclassified from AOCI to earnings from unconsolidated affiliates as a result of amounts excluded from effectiveness testing or as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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 the year ended December 31, 2012:

	(Losses) gains Recognized in AOCI on Derivatives — Effective Portion			Losses Reclassified From AOCI to Earnings — Effective Portion				Losses Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing
	(Millions)
Interest rate derivatives	$	(1	)	$	(10	)	(a)	$	(2	)	(a) (b)
Commodity derivatives	$	(1	)	$	—			$	—
Foreign currency derivatives (c)	$	1		$	—			$	—

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

(b) 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.

(c) Relates to Discovery, our unconsolidated affiliate.

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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:

Commodity Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2013			2012			2011
	(Millions)
Third party:
Realized (losses) gains		$	(19	)	$	4		$	(36	)
Unrealized gains		14			13			43
(Losses) gains from commodity derivative activity, net		$	(5	)	$	17		$	7
Affiliates:
Realized gains		$	73		$	45		$	2
Unrealized (losses) gains		(51		)	8			(1		)
Gains from commodity derivative activity, net —affiliates		$	22		$	53		$	1
Interest Rate Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2013			2012			2011
	(Millions)
Third party:
Realized losses		$	(2	)	$	(7	)	$	(4	)
Unrealized gains		2			7			5
Interest expense		$	—		$	—		$	1

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, 2013
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)		Net (Short) Position (MMBtu)		Net (Short) Position (Bbls)		Net Long Position (MMbtu)
2014	(690,945	)	(21,673,620	)	(5,171,910	)	21,415,000
2015	(745,695	)	(9,458,975	)	(5,691,570	)	1,875,000
2016	(561,922	)	(1,838,564	)	(813,267	)	—
	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	)	—		—		—

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We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of December 31, 2013, 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 — During the year ended December 31, 2013, we issued 1,408,547 of our common units pursuant to an equity distribution agreement entered into in August 2011, or the 2011 equity distribution agreement. We received proceeds of $67 million, net of commissions and offering costs of $2 million, which were used to finance growth opportunities and for general partnership purposes. The 2011 equity distribution agreement provided for the offer and sale of common units having an aggregate offering amount of up to $150 million. As of December 31, 2013, no common units remain available for sale pursuant to this equity distribution agreement and we have deregistered the corresponding registration statement.

In August 2013, we issued 9,000,000 common units at $50.04 per unit. We received proceeds of $434 million, net of offering costs.

In June 2013, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $300 million, which became effective on June 27, 2013. The shelf registration statement allows us to issue additional common units. In November 2013, we entered into an equity distribution agreement, or the 2013 equity distribution agreement, with a group of financial institutions as sales agents. The agreement provides for the offer and sale from time to time, through our sales agents, of common units having an aggregate offering amount of up to $300 million. During the year ended December 31, 2013, we issued 1,839,430 of our common units pursuant to the 2013 equity distribution agreement and received proceeds of $87 million, net of accrued commissions and offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes. As of December 31, 2013, approximately $212 million of the aggregate offering amount remains available for sale pursuant to the 2013 equity distribution agreement.

In March 2013, we issued 2,789,739 common units to DCP Midstream, LLC as partial consideration for 46.67% interest in the Eagle Ford system.

In March 2013, we issued 12,650,000 common units at $40.63 per unit. We received proceeds of $494 million, net of offering costs.

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. Our 9,000,000 and 12,650,000 common units issued in August 2013 and March 2013, respectively, and 2.50% 5-year Senior Notes were issued under this registration statement.

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.

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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.

Definition of Available Cash — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined in the partnership agreement, to unitholders of record on the applicable record date, as determined by our general partner. 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, 2013. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common 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 sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Distributions of Available Cash - 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 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.

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The following table presents our cash distributions paid in 2013, 2012 and 2011:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 14, 2013	$	0.7200	$	82
August 14, 2013	$	0.7100	$	72
May 15, 2013	$	0.7000	$	69
February 14, 2013	$	0.6900	$	54
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

13. Equity-Based Compensation

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

	Year Ended December 31,
	2013		2012		2011
	(Millions)
Performance Phantom Units	$	1	$	1	$	5
Phantom Units	—		—		—
Restricted Phantom Units	1		1		2
Total compensation cost	$	2	$	2	$	7

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, Phillips 66 and Spectra Energy.

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.

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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, 2013, 2,070 units are expected to vest on December 31, 2014 and 10,890 units are expected to vest on December 31, 2015.

At December 31, 2013, 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 approximately 2 years. The following table presents information related to the PPUs:

	Units		Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2011	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	(20,100	)	$	34.57
Forfeited	(7,760	)	$	38.97
Outstanding at December 31, 2012	11,090		$	39.24
Granted	11,450		$	40.88
Vested (b)	(3,800	)	$	40.75
Forfeited	(4,990	)	$	38.77
Outstanding at December 31, 2013	13,750		$	40.36	$	50.33
Expected to vest (c)	12,960		$	40.38	$	50.33

(a) Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation from ConocoPhillips, granted under the 2012 LTIP.

(b) The units vested at 150%.

(c) Based on our December 31, 2013 estimated achievement of specified performance targets, the performance estimate for units granted in both 2013 and 2012 is 100%. The estimated forfeiture rate for units granted in both 2013 and 2012 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.

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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,
	2013		2012		2011
	(Millions)
Fair value of units vested	less than $1		$	1	$	5
Unit-based liabilities paid	$	1	$	5	$	—

Phantom Units- As part of their director fees, we granted 4,400 Phantom Units to directors during the year ended December 31, 2013 and 4,000 Phantom Units to directors during each of the years ended December 31, 2012, and 2011, respectively. All of these units vested in their respective grant years, and were settled in units. The DERs are paid in cash quarterly in arrears. The following table presents information related to the Phantom Units:

	Units		Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2011	—		$	—
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	—		$	—
Granted	4,400		$	46.39
Vested	(4,400	)	$	46.39
Outstanding at December 31, 2013	—		$	—	$	—

The fair value of units vested related to Phantom Units was less than $1 million for each of the years ended December 31, 2013, 2012 and 2011.

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, 2013, 2,070 units are expected to vest on December 31, 2014 and 11,281 units are expected to vest on December 31, 2015. The DERs are paid in cash quarterly in arrears. At December 31, 2013, 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 approximately 2 years. The following table presents information related to the RPUs:

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	Units		Grant Date Weighted- Average Price per Unit		Measurement Date Price per Unit
Outstanding at January 1, 2011	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
Granted	11,590		$	41.94
Vested	(1,950	)	$	41.80
Forfeited	—		$	—
Outstanding at December 31, 2013	13,890		$	41.25	$	50.33
Expected to vest	13,351		$	41.38	$	50.30

(a) Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation from ConocoPhillips, 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:

	Year Ended December 31,
	2013		2012		2011
	(Millions)
Fair value of units vested	less than $1		$	1	$	3
Unit-based liabilities paid	$	1	$	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 10% for units granted in both 2013 and 2012. 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. Net Income or Loss per Limited Partner Unit

Our net income or loss is allocated to the general partner and the limited partners 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 period. Diluted net income or loss per LPU 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

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method. Dilutive potential units include outstanding Performance Units, Phantom Units and Restricted Units. The dilutive effect of unit-based awards was 19,179, 33,043 and 64,286 equivalent units during the years ended December 31, 2013, 2012 and 2011, respectively.

15. 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, 2013 and 2012.

In December 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. In January 2011, we merged two 100% 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 0.975% of taxable margin apportioned to Texas for the year ended December 31, 2013 and 1% for the years ended December 31, 2012 and 2011. For the year ended December 31, 2011, 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 beginning with the year ended December 31, 2012.

Income tax expense consists of the following:

	Year Ended December 31,
	2013			2012			2011
	(Millions)
Current:
Federal income tax expense	$	—		$	—		$	(29	)
State income tax expense	(3		)	(1		)	(2		)
Deferred:
Federal income tax benefit	—			—			29
State income tax (expense) benefit	(5		)	—			1
Total income tax expense	$	(8	)	$	(1	)	$	(1	)

We had net long-term deferred tax liabilities of $11 million and $6 million as of December 31, 2013 and 2012, 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.

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16. Commitments and Contingent Liabilities

Litigation

Prospect — In 2011, we received an arbitration claim, or the Claim, filed with the American Arbitration Association by Prospect Street Energy, LLC and Prospect Street Ventures I, LLC, or together, the Claimants, against EE Group, LLC, or EE Group, and a number of other parties that previously owned, directly or indirectly, our Marysville NGL storage facility, or collectively, the Respondents. EE Group is our indirect subsidiary which we acquired in connection with our acquisition of Marysville Hydrocarbons Holdings, LLC, or Marysville, on December 30, 2010. 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. As of February 2014, we have entered into separate settlement agreements with the Claimants and the other Respondents involved in the arbitration. We believe these settlement agreements substantially mitigate our liability in this matter and therefore, we consider this matter closed.

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.

Insurance - We renewed our insurance policies in May, June and July 2013 for the 2013-2014 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 or our limits in the 2013-2014 insurance year compared with the 2012-2013 insurance year. We are jointly insured with DCP Midstream, LLC for a portion of the 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.

The insurance on Discovery, as placed by Williams Field Service Group LLC, for the 2013-2014 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 continues to elect not to purchase offshore named windstorm property and business interruption insurance coverage for the 2013-2014 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 incorporates 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.

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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 $17 million, $14 million, and $15 million for the years ended December 31, 2013, 2012, and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2013:

	(Millions)
2014	$	16
2015	14
2016	12
2017	10
2018	9
Thereafter	33
Total minimum rental payments	$	94

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, and fractionating NGLs. The segment consists of our 80% interest in the Eagle Ford system, 100% owned Eagle Plant, East Texas system, Southeast Texas system, Michigan system, Northern Louisiana system, Southern Oklahoma system, Wyoming system, 75% interest in the Piceance system, 40% interest in Discovery, and the DJ Basin system.

NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of the NGL storage facility in Michigan, our 20% interest in the Mont Belvieu 1 fractionator, our 12.5% interest in the Mont Belvieu Enterprise fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ Basin NGL fractionators in Colorado, the Seabreeze and Wilbreeze intrastate NGL pipelines, our 33.33% interest in the Front Range interstate NGL pipeline, and our 10% interest in the Texas Express intrastate NGL pipeline.

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 store and 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.

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The following tables set forth our segment information:

Year Ended December 31, 2013:

	Natural Gas Services (d)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,598		$	73		$	380		$	—		$	3,051
Gross margin (a)	$	501		$	72		$	52		—			$	625
Operating and maintenance expense	(184		)	(16		)	(15		)	—			(215		)
Depreciation and amortization expense	(87		)	(6		)	(2		)	—			(95		)
General and administrative expense	—			—			—			(63		)	(63		)
Other expense	(1		)	(3		)	(4		)	—			(8		)
Earnings from unconsolidated affiliates	1			32			—			—			33
Interest expense	—			—			—			(52		)	(52		)
Income tax expense (b)	—			—			—			(8		)	(8		)
Net income (loss)	$	230		$	79		$	31		$	(123	)	$	217
Net income attributable to noncontrolling interests	(17		)	—			—			—			(17		)
Net income (loss) attributable to partners	$	213		$	79		$	31		$	(123	)	$	200
Non-cash derivative mark-to-market (c)	$	(36	)	$	—		$	(1	)	$	1		$	(36	)
Non-cash lower of cost or market adjustments	$	2		$	—		$	2					$	4
Capital expenditures	$	334		$	24		$	5		$	—		$	363
Acquisition expenditures	$	696		$	86		$	—		$	—		$	782
Investments in unconsolidated affiliates	$	133		$	109		$	—		$	—		$	242

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Year Ended December 31, 2012:

	Natural Gas Services (d)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,345		$	64		$	415		$	—		$	2,824
Gross margin (a)	$	503		$	64		$	42		$	—		$	609
Operating and maintenance expense	(166		)	(16		)	(15		)	—			(197		)
Depreciation and amortization expense	(83		)	(6		)	(2		)	—			(91		)
General and administrative expense	—			—			—			(75		)	(75		)
Earnings from unconsolidated affiliates	15			11			—			—			26
Interest expense	—			—			—			(42		)	(42		)
Income tax expense (b)	—			—			—			(1		)	(1		)
Net income (loss)	$	269		$	53		$	25		$	(118	)	$	229
Net income attributable to noncontrolling interests	(13		)	—			—			—			(13		)
Net income (loss) attributable to partners	$	256		$	53		$	25		$	(118	)	$	216
Non-cash derivative mark-to-market (c)	$	20		$	—		$	1		$	—		$	21
Capital expenditures	$	468		$	12		$	4		$	—		$	484
Acquisitions net of cash acquired	$	715		$	30		$	—		$	—		$	745
Investments in unconsolidated affiliates	$	115		$	43		$	—		$	—		$	158

Year Ended December 31, 2011:

	Natural Gas Services (d)			NGL Logistics			Wholesale Propane Logistics			Other			Eliminations (f)			Total
	(Millions)
Total operating revenue	$	3,102		$	57		$	633		$	—		$	(2	)	$	3,790
Gross margin (a)	$	532		$	52		$	51		$	—		$	—		$	635
Operating and maintenance expense	(161		)	(16		)	(15		)	—			—			(192		)
Depreciation and amortization expense	(124		)	(8		)	(3		)	—			—			(135		)
General and administrative expense	—			—			—			(76		)	—			(76		)
Earnings from unconsolidated affiliates	23			—			—			—			—			23
Other operating income	—			1			—			—			—			1
Interest expense	—			—			—			(34		)	—			(34		)
Income tax expense (b)	—			—			—			(1		)	—			(1		)
Net income (loss)	270			29			33			(111		)	—			221
Net income attributable to noncontrolling interests	(30		)	—			—			—			—			(30		)
Net income (loss) attributable to partners	$	240		$	29		$	33		$	(111	)	$	—		$	191
Non-cash derivative mark-to-market (c)	$	42		$	—		$	—		$	(2	)	$	—		$	40
Capital expenditures	$	372		$	9		$	4		$	—		$	—		$	385
Acquisitions net of cash acquired	$	122		$	30		$	—		$	—		$	—		$	152
Investments in unconsolidated affiliates	$	8		$	—		$	—		$	—		$	—		$	8

54

	December 31,
	2013		2012		2011
	(Millions)
Segment long-term assets:
Natural Gas Services (d)	$	3,303	$	2,748	$	2,214
NGL Logistics	555		340		250
Wholesale Propane Logistics	106		105		104
Other (e)	100		84		14
Total long-term assets	4,064		3,277		2,582
Current assets (d)	503		368		373
Total assets	$	4,567	$	3,645	$	2,955

(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b) For the year ended December 31, 2011, 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 years ended December 31, 2013 and 2012 relates primarily to the Texas margin tax.

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

(d) The segment information as of and for the years ended December 31, 2013, 2012 and 2011, includes the results of our Lucerne 1 plant, our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas. Transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information, similar to the pooling method.

(e) Other long-term assets not allocable to segments consist of 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 Logistics segment.

18. Supplemental Cash Flow Information

	Year Ended December 31,
	2013		2012			2011
	(Millions)
Cash paid for interest and income taxes:
Cash paid for interest, net of amounts capitalized	$	40	$	23		$	17
Cash paid for income taxes, net of income tax refunds	$	1	$	1		$	30
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	27	$	47		$	34
Other non-cash additions of property, plant and equipment	$	1	$	8		$	3
Non-cash change in parent advances	$	—	$	(115	)	$	5
Accounts payable related to equity issuance costs	$	1	$	—		$	—

55

19. Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2013 and 2012 were as follows (millions, except per unit amounts):

2013	First (a)			Second (a)			Third (a)			Fourth (a)		Year Ended December 31, 2013 (a)
Total operating revenues	$	749		$	792		$	689		821		3,051
Operating income	$	65		$	117		$	14		48		244
Net income	$	60		$	111		$	6		40		217
Net income attributable to noncontrolling interests	$	(3	)	$	(4	)	$	(3	)	(7	)	(17	)
Net income (loss) attributable to partners	$	57		$	107		$	3		33		200
Net income (loss) allocable to limited partners	$	31		$	86		$	(20	)	8		105
Basic and diluted net income (loss) per limited partner unit	$	0.48		$	1.11		$	(0.24	)	0.09		1.34

(a)Our consolidated results of operations have been adjusted to retrospectively include the historical results of the Lucerne 1 plant for all periods presented.

2012	First (a)			Second (a)			Third (a)			Fourth (a)			Year Ended December 31, 2012 (a)
Total operating revenues	$	855		$	680		$	618		$	671		$	2,824
Operating income	$	52		$	99		$	13		$	82		$	246
Net income	$	44		$	90		$	14		$	81		$	229
Net income attributable to noncontrolling interests	$	(4	)	$	(2	)	$	(2	)	$	(5	)	$	(13	)
Net income attributable to partners	$	40		$	88		$	12		$	76		$	216
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

(a)Our consolidated results of operations have been adjusted to retrospectively include the historical results of the Lucerne 1 plant for all periods presented.

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 statement on Form S-3 filed with the SEC on 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.

56

	Condensed Consolidating Balance Sheet
	December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	12		$	—		$	12
Accounts receivable, net	—		—			342			—			342
Inventories	—		—			67			—			67
Other	—		—			82			—			82
Total current assets	—		—			503			—			503
Property, plant and equipment, net	—		—			3,046			—			3,046
Goodwill and intangible assets, net	—		—			283			—			283
Advances receivable — consolidated subsidiaries	1,805		1,683			—			(3,488		)	—
Investments in consolidated subsidiaries	181		426			—			(607		)	—
Investments in unconsolidated affiliates	—		—			627			—			627
Other long-term assets	—		12			96			—			108
Total assets	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	1	$	350		$	372		$	—		$	723
Advances payable — consolidated subsidiaries	—		—			3,488			(3,488		)	—
Long-term debt	—		1,590			—			—			1,590
Other long-term liabilities	—		—			41			—			41
Total liabilities	1		1,940			3,901			(3,488		)	2,354
Commitments and contingent liabilities
Equity:
Partners’ equity:
Predecessor equity	—		—			40			—			40
Net equity	1,985		187			391			(607		)	1,956
Accumulated other comprehensive loss	—		(6		)	(5		)	—			(11		)
Total partners’ equity	1,985		181			426			(607		)	1,985
Noncontrolling interests	—		—			228			—			228
Total equity	1,985		181			654			(607		)	2,213
Total liabilities and equity	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567

(a) The financial information as of December 31, 2013 includes the results of our Lucerne 1 plant and an 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that were 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.

57

	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	—		—			2,592			—			2,592
Goodwill and intangible assets, net	—		—			291			—			291
Advances receivable — consolidated subsidiaries	873		1,424			—			(2,297		)	—
Investments in consolidated subsidiaries	574		770			—			(1,344		)	—
Investments in unconsolidated affiliates	—		—			304			—			304
Other long-term assets	—		11			79			—			90
Total assets	$	1,447	$	2,208		$	3,634		$	(3,644	)	$	3,645
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	—		—			399			—			399
Net equity	1,447		584			376			(1,344		)	1,063
Accumulated other comprehensive loss	—		(10		)	(5		)	—			(15		)
Total partners’ equity	1,447		574			770			(1,344		)	1,447
Noncontrolling interests	—		—			189			—			189
Total equity	1,447		574			959			(1,344		)	1,636
Total liabilities and equity	$	1,447	$	2,208		$	3,634		$	(3,644	)	$	3,645

(a) The financial information as of December 31, 2012 includes the results of our Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that were 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.

58

	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,763		$	—		$	2,763
Transportation, processing and other	—		—			271			—			271
Gains from commodity derivative activity, net	—		—			17			—			17
Total operating revenues	—		—			3,051			—			3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,426			—			2,426
Operating and maintenance expense	—		—			215			—			215
Depreciation and amortization expense	—		—			95			—			95
General and administrative expense	—		—			63			—			63
Other expense	—		—			8			—			8
Total operating costs and expenses	—		—			2,807			—			2,807
Operating income	—		—			244			—			244
Interest expense, net	—		(52		)	—			—			(52		)
Income from consolidated subsidiaries	200		252			—			(452		)	—
Earnings from unconsolidated affiliates	—		—			33			—			33
Income before income taxes	200		200			277			(452		)	225
Income tax expense	—		—			(8		)	—			(8		)
Net income	200		200			269			(452		)	217
Net income attributable to noncontrolling interests	—		—			(17		)	—			(17		)
Net income attributable to partners	$	200	$	200		$	252		$	(452	)	$	200

(a) The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that were 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.

59

	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	200	$	200	$	269		$	(452	)	$	217
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		4		—			—			4
Other comprehensive income from consolidated subsidiaries	4		—		—			(4		)	—
Total other comprehensive income	4		4		—			(4		)	4
Total comprehensive income	204		204		269			(456		)	221
Total comprehensive income attributable to noncontrolling interests	—		—		(17		)	—			(17		)
Total comprehensive income attributable to partners	$	204	$	204	$	252		$	(456	)	$	204

(a) The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that were 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

	Condensed Consolidating Statement 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	$	—	$	—		$	2,520		$	—		$	2,520
Transportation, processing and other	—		—			234			—			234
Gains from commodity derivative activity, net	—		—			70			—			70
Total operating revenues	—		—			2,824			—			2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,215			—			2,215
Operating and maintenance expense	—		—			197			—			197
Depreciation and amortization expense	—		—			91			—			91
General and administrative expense	—		—			75			—			75
Total operating costs and expenses	—		—			2,578			—			2,578
Operating income	—		—			246			—			246
Interest expense, net	—		(41		)	(1		)	—			(42		)
Earnings from unconsolidated affiliates	—		—			26			—			26
Income from consolidated subsidiaries	216		257			—			(473		)	—
Income before income taxes	216		216			271			(473		)	230
Income tax expense	—		—			(1		)	—			(1		)
Net income	216		216			270			(473		)	229
Net income attributable to noncontrolling interests	—		—			(13		)	—			(13		)
Net income attributable to partners	$	216	$	216		$	257		$	(473	)	$	216

(a) The financial information for the year ended December 31, 2012 includes the results of our Lucerne 1 plant, 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 transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

61

	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	$	216	$	216		$	270		$	(473	)	$	229
Other comprehensive loss:
Reclassification of cash flow hedge losses into earnings	—		10			—			—			10
Net unrealized losses on cash flow hedges	—		(1		)	—			—			(1		)
Other comprehensive income from consolidated subsidiaries	9		—			—			(9		)	—
Total other comprehensive income	9		9			—			(9		)	9
Total comprehensive income	225		225			270			(482		)	238
Total comprehensive income attributable to noncontrolling interests	—		—			(13		)	—			(13		)
Total comprehensive income attributable to partners	$	225	$	225		$	257		$	(482	)	$	225

(a) The financial information for the year ended December 31, 2012 includes the results of our Lucerne 1 plant, 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 transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

62

	Condensed Consolidating Statement 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	$	—	$	—		$	3,574		$	—		$	3,574
Transportation, processing and other	—		—			208			—			208
Gains from commodity derivative activity, net	—		—			8			—			8
Total operating revenues	—		—			3,790			—			3,790
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			3,155			—			3,155
Operating and maintenance expense	—		—			192			—			192
Depreciation and amortization expense	—		—			135			—			135
General and administrative expense	—		—			76			—			76
Other income	—		—			(1		)	—			(1		)
Total operating costs and expenses	—		—			3,557			—			3,557
Operating income	—		—			233			—			233
Interest expense	—		(33		)	(1		)	—			(34		)
Earnings from unconsolidated affiliates	—		—			23			—			23
Income from consolidated subsidiaries	191		224			—			(415		)	—
Income before income taxes	191		191			255			(415		)	222
Income tax expense	—		—			(1		)	—			(1		)
Net income	191		191			254			(415		)	221
Net income attributable to noncontrolling interests	—		—			(30		)	—			(30		)
Net income attributable to partners	$	191	$	191		$	224		$	(415	)	$	191

(a) The financial information for the year ended December 31, 2011 includes the results of our Lucerne 1 plant, 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 transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

63

	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2011 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries				Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	191	$	191		$	254			$	(415	)	$	221
Other comprehensive loss:
Reclassification of cash flow hedge losses into earnings	—		21			—				—			21
Net unrealized losses on cash flow hedges	—		(12		)	(3		)		—			(15		)
Other comprehensive income from consolidated subsidiaries	6		(3		)	—				(3		)	—
Total other comprehensive income	6		6			(3		)	—	(3		)	6
Total comprehensive income	197		197			251				(418		)	227
Total comprehensive income attributable to noncontrolling interests	—		—			(30		)		—			(30		)
Total comprehensive income attributable to partners	$	197	$	197		$	221			$	(418	)	$	197

(a) The financial information for the year ended December 31, 2011 includes the results of our Lucerne 1 plant, 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 transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

64

	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2013 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(45	)	$	387		$	3		$	345
INVESTING ACTIVITIES:
Intercompany transfers	(806		)	(258		)	—			1,064			—
Capital expenditures	—			—			(363		)	—			(363		)
Acquisitions, net of cash acquired	—			—			(696		)	—			(696		)
Acquisition of unconsolidated affiliates	—			—			(86		)	—			(86		)
Investments in unconsolidated affiliates	—			—			(242		)	—			(242		)
Net cash (used in) provided by investing activities	(806		)	(258		)	(1,387		)	1,064			(1,387		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,064			(1,064		)	—
Proceeds from long-term debt	—			1,957			—			—			1,957
Payments of long-term debt	—			(1,988		)	—			—			(1,988		)
Proceeds from issuance of commercial paper	—			335			—			—			335
Payments of deferred financing costs	—			(4		)	—			—			(4		)
Excess purchase price over acquired interests and commodity hedges	—			—			(85		)	—			(85		)
Proceeds from issuance of common units, net of offering costs	1,083			—			—			—			1,083
Net change in advances to predecessor from DCP Midstream, LLC	—			—			11			—			11
Distributions to limited partners and general partner	(277		)	—			—			—			(277		)
Distributions to noncontrolling interests	—			—			(24		)	—			(24		)
Contributions from noncontrolling interests	—			—			46			—			46
Distributions to DCP Midstream, LLC	—			—			(3		)	—			(3		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash provided by (used in) financing activities	806			300			1,010			(1,064		)	1,052
Net change in cash and cash equivalents	—			(3		)	10			3			10
Cash and cash equivalents, beginning of period	—			3			2			(3		)	2
Cash and cash equivalents, end of period	$	—		$	—		$	12		$	—		$	12

(a) The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that were 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.

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	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	$	—		$	(39	)	$	142		$	(1	)	$	102
INVESTING ACTIVITIES:
Intercompany transfers	(274		)	(827		)	—			1,101			—
Capital expenditures	—			—			(484		)	—			(484		)
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) provided by investing activities	(274		)	(827		)	(1,384		)	1,101			(1,384		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,101			(1,101		)	—
Proceeds from long-term debt	—			2,665			—			—			2,665
Payments of long-term 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	—			—			336			—			336
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			1,238			(1,101		)	1,276
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 during the year ended December 31, 2012 includes the results of our Lucerne 1 plant, 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 transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

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	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	$	—		$	(31	)	$	448		$	—		$	417
INVESTING ACTIVITIES:
Intercompany transfers	(38		)	(62		)	—			100			—
Capital expenditures	—			—			(385		)	—			(385		)
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) provided by investing activities	(38		)	(62		)	(538		)	100			(538		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			100			(100		)	—
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	—			—			52			—			52
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			89			(100		)	122
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 Lucerne 1 plant, 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.

The parent guarantor, subsidiary issuer and non-guarantor subsidiaries participate in a cash pooling program, whereby cash balances are generally swept daily between the parent guarantor and the non-guarantor subsidiaries bank accounts and those of the subsidiary issuer.

Subsequent to the issuance of the 2013 financial statements, management determined that intercompany transfers between the parent guarantor and the non-guarantor subsidiaries, as well as the subsidiary issuer and the non-guarantor subsidiaries,

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should be classified as investing activities by the parent guarantor and subsidiary issuer and financing activities by the non-guarantor subsidiaries, within the condensed consolidating statements of cash flows. The intercompany transfers had previously been reported as operating activities by the parent guarantor, subsidiary issuer and non-guarantor subsidiaries. The classification of these intercompany transfers has been corrected in the condensed consolidating financial statements for the years ended December 31, 2013, 2012 and 2011. This correction has no impact on the consolidated statement of cash flows for all years presented. These amounts have been included within the line item “intercompany transfers” in investing and financing activities within the condensed consolidating statements of cash flows. The changes to the previously reported amounts are summarized as follows:

	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	806		$	258		$	(1,064	)	$	—		$	—
Net cash (used in) provided by investing activities	$	(806	)	$	(258	)	$	—		$	1,064		$	—
Net cash provided by (used in) financing activities	$	—		$	—		$	1,064		$	(1,064	)	$	—
Year Ended December 31, 2012
Net cash (used in) provided by operating activities	$	274		$	827		$	(1,101	)	$	—		$	—
Net cash (used in) provided by investing activities	$	(274	)	$	(827	)	$	—		$	1,101		$	—
Net cash provided by (used in) financing activities	$	—		$	—		$	1,101		$	(1,101	)	$	—
Year Ended December 31, 2011
Net cash (used in) provided by operating activities	$	38		$	62		$	(100	)	$	—		$	—
Net cash (used in) provided by investing activities	$	(38	)	$	(62	)	$	—		$	100		$	—
Net cash provided by (used in) financing activities	$	—		$	—		$	100		$	(100	)	$	—

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21. Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2013, 2012, and 2011 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, 2013
Environmental	$	2	$	1	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	3	$	1	$	—	$	(1	)	$	3
December 31, 2012
Environmental	$	3	$	—	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	4	$	—	$	—	$	(1	)	$	3
December 31, 2011
Environmental	$	3	$	—	$	—	$	—		$	3
Litigation	1		—		—		(1		)	—
Other (a)	—		1		—		—			1
	$	4	$	1	$	—	$	(1	)	$	4

(a) Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in other long-term assets, and other contingency liabilities, which are included in other current liabilities.

22. Subsequent Events

On January 28, 2014, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.7325 per unit, payable on February 14, 2014 to unitholders of record on February 7, 2014.

On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC and its affiliates for the contribution or acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (iii) the Lucerne 1 plant; and (iv) the Lucerne 2 plant. Total consideration for these transactions at closing was $1,220 million, subject to certain working capital and other customary adjustments. These transactions closed in March 2014. The Southern Hills pipeline is engaged in the business of transporting NGLs, and consists of approximately 800 miles of pipeline, with an expected capacity of 175 MBbls/d after completion of planned pump stations. The pipeline provides NGL takeaway service from the Midcontinent to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub.The Southern Hills pipeline began taking flows in the first quarter of 2013 and was placed into service in June 2013. The Sand Hills pipeline is also engaged in the business of transporting NGLs and consists of approximately 720 miles of pipeline, with an expected initial capacity of 200 MBbls/d after completion of pump stations, and possible further capacity increases with the installation of additional pump stations. The pipeline provides NGL takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills pipeline began taking flows in the fourth quarter of 2012 and was placed into service in June 2013.

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