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

Exhibit 99.4

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

DCP MIDSTREAM, LP CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm	1
Consolidated Balance Sheets as of December 31, 2016 and 2015	2
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	3
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014	4
Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014	5
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	7
Notes to Consolidated Financial Statements	8

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, LP and subsidiaries (the "Partnership") as of December 31, 2016 and 2015, 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, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Discovery Producer Services, LLC (“Discovery”), an investment of the Partnership which is accounted for by the use of the equity method (see note 10 to the consolidated financial statements). The accompanying 2016 and 2015 consolidated financial statements of the Partnership include its equity investment in Discovery of $386 million and $406 million at December 31, 2016 and 2015, respectively, and its equity earnings in Discovery of $74 million and $55 million for the years ended December 31, 2016 and 2015, respectively. The consolidated financial statements of Discovery as of December 31, 2016 and 2015 and for the years then ended, were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for the Partnership’s equity investment and equity earnings in Discovery, is based on the report of the other auditors. We have applied auditing procedures to the adjustments to reflect the Partnership’s equity investment and equity earnings in Discovery in accordance with accounting principles generally accepted in the United States of America.

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, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, the consolidated financial statements give retrospective effect to the January 1, 2017 acquisition by the Partnership of 100% of the ownership interest in the DCP Midstream Business from DCP Midstream, LLC, as a transfer of net assets between entities under common control, which has been accounted for in a manner similar to a pooling of interests.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2016, based on the criteria established in the Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 15, 2017 expressed an unqualified opinion on the Partnership’s internal control over financial reporting (not presented herein).

/s/ Deloitte & Touche LLP

Denver, Colorado

February 15, 2017

(May 24, 2017 as to Notes 1, 4 and 25)

1

DCP MIDSTREAM, LP

CONSOLIDATED BALANCE SHEETS

	December 31,   2016			December 31,   2015
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	3
Accounts receivable:
Trade, net of allowance for doubtful accounts of $4 million	652			448
Affiliates	134			75
Other	6			21
Inventories	72			51
Unrealized gains on derivative instruments	42			156
Collateral cash deposits	71			7
Other	16			43
Total current assets	994			804
Property, plant and equipment, net	9,069			9,428
Goodwill	236			242
Intangible assets, net	137			149
Investments in unconsolidated affiliates	2,969			2,992
Unrealized gains on derivative instruments	5			19
Other long-term assets	201			251
Total assets	$	13,611		$	13,885
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	677		$	480
Affiliates	48			40
Other	10			25
Current maturities of long-term debt	500			—
Unrealized losses on derivative instruments	91			69
Accrued interest	72			72
Accrued taxes	49			38
Accrued wages and benefits	72			71
Capital spending accrual	20			20
Other	84			84
Total current liabilities	1,623			899
Long-term debt	4,907			5,669
Unrealized losses on derivative instruments	1			12
Deferred income taxes	28			26
Other long-term liabilities	199			187
Total liabilities	6,758			6,793
Commitments and contingent liabilities
Equity:
Predecessor equity	4,220			4,287
Limited partners (114,749,848 and 114,742,948 common units issued and outstanding, respectively)	2,591			2,762
General partner	18			18
Accumulated other comprehensive loss	(8		)	(8		)
Total partners’ equity	6,821			7,059
Non-controlling interests	32			33
Total equity	6,853			7,092
Total liabilities and equity	$	13,611		$	13,885

See accompanying notes to consolidated financial statements.

2

DCP MIDSTREAM, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016			2015			2014
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	5,317		$	6,014		$	11,390
Sales of natural gas, NGLs and condensate to affiliates	952			765			2,030
Transportation, processing and other	647			532			517
Trading and marketing (losses) gains, net	(23		)	119			88
Total operating revenues	6,893			7,430			14,025
Operating costs and expenses:
Purchases of natural gas and NGLs	4,978			5,563			11,363
Purchases of natural gas and NGLs from affiliates	483			418			465
Operating and maintenance expense	670			732			773
Depreciation and amortization expense	378			377			348
General and administrative expense	292			281			277
Asset impairments	—			912			18
Other (income) expense, net	(65		)	10			7
(Gain) loss on sale of assets, net	(35		)	(42		)	7
Restructuring costs	13			11			—
Total operating costs and expenses	6,714			8,262			13,258
Operating income (loss)	179			(832		)	767
Interest expense, net	(321		)	(320		)	(287		)
Earnings from unconsolidated affiliates	282			184			82
Income (loss) before income taxes	140			(968		)	562
Income tax (expense) benefit	(46		)	102			(11		)
Net income (loss)	94			(866		)	551
Net income attributable to non-controlling interests	(6		)	(5		)	(4		)
Net income (loss) attributable to partners	88			(871		)	547
Net loss (income) attributable to predecessor operations	224			1,099			(130		)
General partner’s interest in net income	(124		)	(124		)	(114		)
Net income allocable to limited partners	$	188		$	104		$	303
Net income per limited partner unit — basic and diluted	$	1.64		$	0.91		$	2.84
Weighted-average limited partner units outstanding — basic and diluted	114.7			114.6			106.6

See accompanying notes to consolidated financial statements.

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DCP MIDSTREAM, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2016			2015			2014
	(Millions)
Net income (loss)	$	94		$	(866	)	$	551
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			1			2
Total other comprehensive income	—			1			2
Total comprehensive income (loss)	94			(865		)	553
Total comprehensive income attributable to non-controlling interests	(6		)	(5		)	(4		)
Total comprehensive income (loss) attributable to partners	$	88		$	(870	)	$	549

See accompanying notes to consolidated financial statements.

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DCP MIDSTREAM, LP

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

				Partners’ Equity
	Predecessor Equity			Limited Partners			General Partner			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total Equity
	(Millions)
Balance, January 1, 2016	$	4,287		$	2,762		$	18		$	(8	)	$	33		$	7,092
Net (loss) income	(224		)	188			124			—			6			94
Net change in parent advances	157			—			—			—			—			157
Distributions to limited partners and general partner	—			(359		)	(124		)	—			—			(483		)
Distributions to non-controlling interests	—			—			—			—			(7		)	(7		)
Balance, December 31, 2016	$	4,220		$	2,591		$	18		$	(8	)	$	32		$	6,853

See accompanying notes to consolidated financial statements.

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DCP MIDSTREAM, LP

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

				Partners’ Equity
	Predecessor Equity			Limited  Partners			General  Partner			Accumulated  Other Comprehensive (Loss) Income			Non-controlling Interests			Total Equity
	(Millions)
Balance, January 1, 2015	$	2,189		$	2,984		$	18		$	(9	)	$	33		$	5,215
Net (loss) income	(1,099		)	104			124			—			5			(866		)
Other comprehensive income	—			—			—			1			—			1
Net change in parent advances	3,197			—			—			—			—			3,197
Issuance of 793,080 common units to the public	—			31			—			—			—			31
Distributions to limited partners and general partner	—			(358		)	(124		)	—			—			(482		)
Distributions to non-controlling interests	—			—			—			—			(5		)	(5		)
Contributions from DCP Midstream, LLC	—			1			—			—			—			1
Balance, December 31, 2015	$	4,287		$	2,762		$	18		$	(8	)	$	33		$	7,092

				Partners’ Equity
	Predecessor Equity			Limited  Partners			General  Partner			Accumulated  Other Comprehensive (Loss) Income			Non-controlling Interests			Total Equity
	(Millions)
Balance, January 1, 2014	$	2,406		$	1,948		$	8		$	(11	)	$	34		$	4,385
Net income	130			303			114			—			4			551
Other comprehensive income	—			—			—			2			—			2
Net change in parent advances	(347		)	—			—			—			—			(347		)
Issuance of 4,497,158 units to DCP Midstream, LLC and affiliates	—			225			—			—			—			225
Excess purchase price over carrying value of interests acquired in March 2014 Transactions	—			(178		)	—			—			—			(178		)
Issuance of 20,407,571 common units to the public	—			1,002			—			—			—			1,002
Distributions to limited partners and general partner	—			(316		)	(104		)	—			—			(420		)
Distributions to non-controlling interests	—			—			—			—			(5		)	(5		)
Balance, December 31, 2014	$	2,189		$	2,984		$	18		$	(9	)	$	33		$	5,215

See accompanying notes to consolidated financial statements.

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DCP MIDSTREAM, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015			2014
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	94		$	(866	)	$	551
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	378			377			348
Earnings from unconsolidated affiliates	(282		)	(184		)	(82		)
Distributions from unconsolidated affiliates	356			217			141
Net unrealized losses (gains) on derivative instruments	139			(46		)	(43		)
(Gain) loss on sale of assets	(35		)	(42		)	7
Asset impairments	—			912			18
Other, net	68			(68		)	36
Change in operating assets and liabilities, which provided cash, net of effects of acquisitions:
Accounts receivable	(247		)	479			400
Inventories	(21		)	29			16
Accounts payable	199			(381		)	(467		)
Other, net	(4		)	15			(108		)
Net cash provided by operating activities	645			442			817
INVESTING ACTIVITIES:
Capital expenditures	(144		)	(811		)	(1,384		)
Investments in unconsolidated affiliates, net	(53		)	(64		)	(161		)
Proceeds from sale of assets	163			164			30
Net cash used in investing activities	(34		)	(711		)	(1,515		)
FINANCING ACTIVITIES:
Proceeds from long-term debt	3,353			7,216			719
Payments of long-term debt	(3,628		)	(7,196		)	—
Payments of commercial paper, net	—			(1,012		)	(288		)
Payments of deferred financing costs	(5		)	(4		)	(12		)
Proceeds from issuance of common units, net of offering costs	—			31			1,001
Net change in advances to predecessor from DCP Midstream, LLC	157			1,697			(301		)
Distributions to limited partners and general partner	(483		)	(482		)	(420		)
Distributions to non-controlling interests	(7		)	(5		)	(5		)
Net cash (used in) provided by financing activities	(613		)	245			694
Net change in cash and cash equivalents	(2		)	(24		)	(4		)
Cash and cash equivalents, beginning of period	3			27			31
Cash and cash equivalents, end of period	$	1		$	3		$	27

See accompanying notes to consolidated financial statements.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

1. Description of Business and Basis of Presentation

DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or "the Partnership" is a Delaware limited partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets.

Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information regarding these segments, see Note 21 - Business Segments.

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 its affiliates and 50% by Enbridge, Inc. and its affiliates, or Enbridge. During the third quarter of 2016, Spectra Energy entered into an Agreement and Plan of Merger (the "Merger Agreement") with Enbridge and completed the merger during the first quarter of 2017. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of December 31, 2016 DCP Midstream, LLC owned approximately 21.4% of us, including limited partner and general partner interests.

On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. Our predecessor results consist of all of the ownership interests of DCP Midstream, LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of The DCP Midstream Business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price deficit of DCP Midstream, LLC’s basis in the net assets is recognized as 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. Following the Transaction, DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests.

For additional information regarding the Transaction, see Note 4 - Acquisitions.

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.

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

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.

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.

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.

Accounting for Risk Management Activities and Financial Instruments - We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives may be designated as 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 other non-trading derivatives, which are related to asset-based activities for which hedge accounting or 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 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
Trading Derivatives	Mark-to-market method (a)	Net basis in trading and marketing gains and losses
Non-Trading Derivatives:
Cash Flow Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item
Fair Value Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item
Normal Purchases or Normal Sales	Accrual method (c)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale
Other Non-Trading Derivative Activity	Mark-to-market method (a)	Net basis in trading and marketing gains and losses, net

______________

(a) Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in trading and marketing gains and losses, net during the current period.

(b) Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.

(c) Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.

Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

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.

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.

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.

Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

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. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows.

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.

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 that is other than temporary, 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 less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

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. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Unamortized Debt Discount and Expense - Premiums, discounts, and expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The premiums, discounts, and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt.

11

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

Non-controlling Interest - Non-controlling 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 non-controlling interest in equity. Distributions to and contributions from non-controlling interests represent cash payments to and cash contributions from, respectively, such third-party and affiliate investors.

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 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. 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/index 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 published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in 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/index 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.

• Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs.

Our trading and 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.

12

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014

• 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. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for commodity derivative activity net in the consolidated statements of operations as trading and marketing gains and losses. 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.

Purchases of natural gas and NGLs - Purchases of natural gas and NGLs represent physical purchases from suppliers.

Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2016, 2015 and 2014. We had significant transactions with affiliates for the years ended December 31, 2016, 2015 and 2014. See Note 6, Agreements and Transactions with Related Parties and 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.

Equity-Based Compensation — Liability classified share-based compensation cost is remeasured at each reporting date at fair value, based on the closing security 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.

Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. We owned a corporation that filed its own federal and state corporate income tax returns, which we elected to convert to a limited liability company in 2016. 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 income tax 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 limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

13

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

3. New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated statement of cash flows.

FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

FASB ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016. The Partnership has adpoted the ASU and it did not have any impact on our consolidated results of operations, cash flows and financial position.

FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU was effective for annual reporting periods beginning after December 15, 2015. The retrospective adoption of this ASU has been implemented and did not have any impact on our consolidated results of operations, cash flows and financial position.

FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.

4. Acquisitions

On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. This represents a Transaction between entities under common control and a change in reporting entity.

Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, the General Partner, in its capacity as the general partner of the Partnership, entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.

14

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

On January 1, 2015, we entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, we paid $1 million for our interest in the joint venture. The total consideration of approximately $26 million included our proportionate share in construction costs for expansion of the existing Panola NGL pipeline. In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016.

On March 31, 2014, DCP Midstream, LLC and its affiliates contributed to us: (i) a 33.33% membership interest in DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (ii) a 33.33% membership interest in DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline; and (iii) the remaining 20% interest in DCP SC Texas GP, or the Eagle Ford system.

On March 28, 2014, we acquired from DCP Midstream, LLC and its affiliates (i) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (ii) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, or the Lucerne 2 plant. Together with the contribution of the interests in the Sand Hills and Southern Hills pipelines and the remaining 20% interest in the Eagle Ford system, the acquisition of the Lucerne 1 and 2 plants are collectively referred to hereafter as the March 2014 Transactions.

Total consideration for the March 2014 Transactions at closing was $1,220 million, less customary working capital and other adjustments. $225 million of the consideration was funded by the issuance at closing of 2,098,674 of our common units to DCP Midstream, LLC, 1,399,116 of our common units to DCP LP Holdings, LLC, and 999,368 of our common units to DCP Midstream GP, LP. The remainder of the consideration was financed by a portion of the issuance of 14,375,000 common units to the public and the proceeds from our 5.60% 30-year Senior Notes and 2.70% five-year Senior Notes offering. The total consideration over the carrying value of the net assets of the Sand Hills and Southern Hills pipelines, the remaining 20% of the Eagle Ford system, and the Lucerne 1 and Lucerne 2 plants resulted in an excess purchase price of $178 million which was recorded as a decrease in limited partners' equity in the consolidated statement of changes in equity.

5. Dispositions

In May 2016, we entered into a purchase and sale agreement with a third party to sell our 100% interest in our Northern Louisiana system, which primarily consisted of certain gas processing plants and gathering systems, for approximately $160 million, subject to customary purchase price adjustments. This transaction closed on July 1, 2016 and we recorded a gain of $41 million, net of goodwill, in the third quarter of 2016.

In July 2015, we entered into a purchase and sale agreement with a third party to sell a gas processing plant and gathering system for approximately $120 million, subject to customary purchase price adjustments. This transaction closed on August 26, 2015, and we recognized a $59 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015.

In May 2015, we entered into purchase and sale agreements with WTG Benedum Joint Venture to sell our 33% interest in the Benedum gas processing plant and 100% interest in the Benedum gathering system, or Benedum, for approximately $21 million, subject to customary purchase price adjustments. This transaction closed on May 13, 2015, and we recognized a $27 million loss on sale, which included $2 million of goodwill, in the consolidated statement of operations for the year ended December 31, 2015.

In January 2015, we entered into a purchase and sale agreement with Mustang Gas Products, LLC to sell our approximate 44% interest in the Dover-Hennessey gas processing plant and gathering system for approximately $29 million, subject to customary purchase price adjustments. This transaction closed on January 30, 2015, and we recognized a $10 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015.

In August 2014, we entered into a purchase and sale agreement with American Midstream, LLC to divest our two-thirds ownership interest in Main Pass Oil Gathering Company, or Main Pass, for total proceeds of approximately $14 million and selling costs of approximately $3 million. This transaction closed on August 11, 2014, and we recognized a $6 million loss on sale in the consolidated statements of operations for the year ended December 31, 2014.

15

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

6. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”) with DCP Services, LLC, an affiliate of DCP Midstream, LLC, which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. For the years ended December 31, 2016, 2015 and 2014, the consolidated statements of operations include employee related costs that were charged by DCP Midstream, LLC of $206 million, $224 million and $225 million, respectively within operating and maintenance expense, and $197 million, $194 million and $184 million, respectively within general and administrative expense and restructuring costs.

Phillips 66 and its Affiliates

We sell a portion of our residue gas and NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and its affiliates in the ordinary course of business.

Enbridge and its Affiliates including Spectra Energy Corp

We purchase NGLs from Enbridge and its affiliates. We anticipate continuing to purchase commodities and provide services to Enbridge and its affiliates in the ordinary course of business.

Unconsolidated Affiliates

We, along with other third party shippers, have entered into 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15-year agreements, which commenced at each of the pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs.

Under the terms of their respective operating agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, 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 service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the respective operating agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.

We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.

16

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Year Ended December 31,
	2016		2015		2014
	(Millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	909	$	695	$	1,960
Purchases of natural gas and NGLs from affiliates	$	18	$	—	$	11
Operating and maintenance and general administrative expenses	$	2	$	4	$	3
Enbridge (including Spectra Energy Corp.):
Transportation, storage and processing to affiliates	$	—	$	—	$	14
Purchases of natural gas and NGLs from affiliates	$	33	$	50	$	88
Operating and maintenance and general administrative expenses	$	4	$	6	$	10
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	43	$	70	$	70
Transportation, storage and processing	$	5	$	3	$	12
Purchases of natural gas and NGLs from affiliates	$	432	$	368	$	366

We had balances with affiliates as follows:

	December 31,
	2016		2015
	(Millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	115	$	54
Accounts payable	$	4	$	3
Other assets	$	2	$	1
Enbridge (including Spectra Energy Corp.):
Accounts receivable	$	1	$	—
Accounts payable	$	3	$	4
Other assets	$	1	$	1
Other liabilities	$	1	$	—
Unconsolidated affiliates:
Accounts receivable	$	18	$	21
Accounts payable	$	41	$	33
Other assets	$	5	$	31

7. Inventories

Inventories were as follows:

	December 31,
	2016		2015
	(Millions)
Natural gas	$	28	$	29
NGLs	44		22
Total inventories	$	72	$	51

17

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

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 and NGLs in the consolidated statements of operations. We recognized $3 million, $8 million and $24 million in lower of cost or market adjustments during the years ended December 31, 2016, 2015, and 2014, respectively.

8. Property, Plant and Equipment

Property, plant and equipment by classification were as follows:

		December 31,
	Depreciable Life	2016			2015
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	8,560		$	8,815
Processing, storage, and terminal facilities	35 — 60 Years	5,134			5,102
Other	3 —  30 Years	502			485
Construction work in progress		171			196
Property, plant and equipment		14,367			14,598
Accumulated depreciation		(5,298		)	(5,170		)
Property, plant and equipment, net		$	9,069		$	9,428

Interest capitalized on construction projects was less than $1 million for the year ended December 31, 2016. Interest capitalized on construction projects for the years ended December 31, 2015 and 2014 was $32 million and $34 million, respectively.

Depreciation expense was $366 million, $358 million and $327 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

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.

The following table summarizes changes in the asset retirement obligations included in our balance sheets:

	December 31,
	2016 (a)			2015 (a)
	(millions)
Balance, beginning of period	$	120		$	117
Accretion expense	7			7
Revisions in estimated cash flows	(3		)	(4		)
Balance, end of period	$	124		$	120

(a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operating and maintenance expense in our consolidated statement of operations. Accretion expense for the year ended December 31, 2014 was $6 million.

18

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

9. Goodwill and Intangible Assets

We performed our annual goodwill assessment during the third quarter of 2016 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 (including forecasted volumes and commodity prices), as well as historical and other factors. 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.

During the second quarter of 2015, we recognized a goodwill impairment based on our best estimate of the impairment resulting from the performance of the hypothetical purchase price allocation which totaled $378 million for our Mid-continent and Permian reporting units and $49 million for our Collbran, Michigan, and Southeast Texas reporting units. We completed the hypothetical purchase price allocation in the third quarter of 2015 and after completing the analysis, there was no remaining fair value to assign to the goodwill of the Collbran reporting unit. As a result, we recorded an additional impairment of $33 million in the third quarter of 2015.

We performed our annual goodwill assessment during the quarter ended September 30, 2015. We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of our annual goodwill assessment.

The change in carrying amount of goodwill in each of our reportable segments was as follows:

	Year Ended December 31,
	2016								2015
	(Millions)
	Gathering and Processing			Logistics and Marketing		Total			Gathering and Processing			Logistics and Marketing		Total
Balance, beginning of period	$	170		$	72	$	242		$	632		$	72	$	704
Impairment	—			—		—			(460		)	—		(460		)
Dispositions	$	(6	)	$	—	$	(6	)	$	(2	)	$	—	$	(2	)
Balance, end of period	$	164		$	72	$	236		$	170		$	72	$	242

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

	December 31,
	2016			2015
	(Millions)
Gross carrying amount	$	410		$	410
Accumulated amortization	(151		)	(139		)
Accumulated impairment	(122		)	(122		)
Intangible assets, net	$	137		$	149

We recorded amortization expense of $12 million, $19 million and $21 million for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016, the remaining amortization periods ranged from approximately 2 years to 19 years, with a weighted-average remaining period of approximately 14 years.

19

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Estimated future amortization for these intangible assets is as follows:

Estimated Future Amortization
(Millions)
2017	$	11
2018	11
2019	11
2020	11
2021	11
Thereafter	82
Total	$	137

10. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	December 31,   2016		December 31,   2015
		(Millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,507	$	1,492
DCP Southern Hills Pipeline, LLC	66.67%	754		764
Discovery Producer Services LLC	40.00%	385		405
Front Range Pipeline LLC	33.33%	165		170
Texas Express Pipeline LLC	10.00%	93		96
Panola Pipeline Company, LLC	15.00%	25		19
Mont Belvieu Enterprise Fractionator	12.50%	23		25
Mont Belvieu 1 Fractionator	20.00%	10		11
Other	Various	7		10
Total investments in unconsolidated affiliates		$	2,969	$	2,992

There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $662 million and $677 million as of December 31, 2016 and 2015, respectively, which is associated with and being amortized over the life of the underlying long-lived assets of Sand Hills.

There was an excess of the carrying amount of the investment over the underlying equity of Southern Hills of $148 million and $152 million as of December 31, 2016 and 2015, respectively, which is associated with, and being amortized over the life of, the underlying long-lived assets of Southern Hills.

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery Producer Services, LLC, or Discovery, of $20 million and $24 million as of December 31, 2016 and 2015, 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 $5 million at both December 31, 2016 and 2015, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Front Range.

There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million at both December 31, 2016 and 2015, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Texas Express.

There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I Fractionation Facility, or Mont Belvieu I, of $2 million and $3 million as of December 31, 2016 and 2015, respectively, which is associated with, and is being amortized over the life of the underlying long-lived assets of Mont Belvieu I.

20

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Earnings from investments in unconsolidated affiliates were as follows:

		Year Ended December 31,
		2016		2015		2014
	(Millions)
DCP Sand Hills Pipeline, LLC		$	110	$	63	$	26
Discovery Producer Services LLC		73		54		7
DCP Southern Hills Pipeline, LLC		44		18		15
Front Range Pipeline LLC		19		17		2
Mont Belvieu Enterprise Fractionator		16		15		17
Mont Belvieu 1 Fractionator		9		9		12
Texas Express Pipeline LLC		9		8		3
Other		2		—		—
Total earnings from unconsolidated affiliates		$	282	$	184	$	82

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

		Year Ended December 31,
		2016		2015		2014
	(Millions)
Statements of operations (a):
Operating revenue		$	1,311	$	1,142	$	859
Operating expenses		$	539	$	541	$	503
Net income		$	768	$	600	$	354

	December 31,
	2016			2015
	(Millions)
Balance sheets (a):
Current assets	$	232		$	240
Long-term assets	5,274			5,224
Current liabilities	(156		)	(167		)
Long-term liabilities	(205		)	(230		)
Net assets	$	5,145		$	5,067

(a) In accordance with the Panola Pipeline Company, LLC, or Panola, joint venture agreement, earnings

began to accrue to the Partnership’s interest on February 1, 2016. Accordingly, activity related to Panola

is included in the above tables as of and for the year ended December 31, 2016.

11. 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, and/or the liquidity of the market.

21

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

• Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us 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 13 - Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. 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 level of judgment involved in the most significant input 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.

22

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions.

Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices 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 it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using 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 may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been 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.

23

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Benefits

We offer certain eligible DCP Midstream, LLC executives the opportunity to participate in our DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan, or the EDC Plan. All amounts contributed to and earned by the EDC Plan’s investments are held in a trust account, which is managed by a third-party service provider. The trust account is invested in short-term money market securities and mutual funds. These investments are recorded at fair value, with any changes in fair value being recorded as a gain or loss in our consolidated statements of operations. Given that the value of the short-term money market securities and mutual funds are publicly traded and for which market prices are readily available, these investments are classified within Level 1.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived 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.

There were no assets measured at fair value on a non-recurring basis as of December 31, 2016. The following table presents the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and by valuation hierarchy, as of December 31, 2015:

	Fair Value Measurements Using
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
December 31, 2015:
Goodwill	$	—	$	—	$	—	$	—	$	460
Property, plant and equipment	87		—		—		87		302
Intangible assets	36		—		—		36		122
Other assets	50		—		—		50		28
Total non-recurring assets measured at fair value	$	173	$	—	$	—	$	173	$	912

24

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

The following table presents the financial instruments carried at fair value as of December 31, 2016 and 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above:

	December 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total Carrying Value			Level 1			Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	5		$	28		$	9		$	42		$	23		$	98		$	35		$	156
Short-term investments (b)	$	—		$	—		$	—		$	—		$	2		$	—		$	—		$	2
Long-term assets:
Commodity derivatives (c)	$	—		$	—		$	5		$	5		$	3		$	12		$	4		$	19
Mutual funds (d)	$	—		$	—		$	—		$	—		$	8		$	—		$	—		$	8
Current liabilities:
Commodity derivatives (e)	$	(11	)	$	(57	)	$	(23	)	$	(91	)	$	(16	)	$	(30	)	$	(23	)	$	(69	)
Long-term liabilities:
Commodity derivatives (f)	$	(1	)	$	—		$	—		$	(1	)	$	(1	)	$	(5	)	$	(6	)	$	(12	)

(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 other long-term assets in our consolidated balance sheets.

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

(f) 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. Amounts transferred in and out of Level 1 and Level 2 are reflected at fair value as of the end of the period. During the years ended December 31, 2016 and 2015, 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 would reflect such items in the table below within the “Transfers into/out of Level 3” captions.

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 table below, the gains or losses in the table do not reflect the effect of our total risk management activities.

25

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Commodity Derivative Instruments
	Current Assets			Long- Term Assets		Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2016 (a):
Beginning balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) included in earnings (b)	3			1		(15		)	6
Settlements	(29		)	—		15			—
Ending balance	$	9		$	5	$	(23	)	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	9		$	3	$	(23	)	$	6
Year ended December 31, 2015 (a):
Beginning balance	$	23		$	3	$	(45	)	$	(12	)
Net unrealized gains (losses) included in earnings (b)	(82		)	1		(29		)	6
Transfers out of Level 3 (c)	—			—		1			—
Settlements	(25		)	—		50			—
Novation (d)	119			—		—			—
Ending balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	(84	)	$	1	$	(23	)	$	4

(a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015.

(b) Represents the amount of total gains or losses for the period, included in trading and marketing gains or losses, net, in our consolidated statements of operations.

(c) Amounts transferred out of Level 3 are reflected at fair value as of the end of the period.

(d) Represents the March 2015 novation of certain fixed price commodity derivatives.

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 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 these contracts.

	December 31, 2016
Product Group	Fair Value			Forward Curve Range
	(Millions)
Assets
NGLs	$	14		$0.25-$1.20	Per gallon
Liabilities
NGLs	$	(23	)	$0.25-$1.23	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 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.

26

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

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, if any, 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, if any, 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 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.

We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our revolving credit facility 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 classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of December 31, 2016 and 2015, the carrying value and fair value of our total debt, includiing current maturities, were as follows:

		December 31, 2016		December 31, 2015
		Carrying Value (a)	Fair Value	Carrying Value (a)	Fair Value
	(Millions)
Total debt		5,430	5,395	5,704	4,754

(a) Excludes unamortized issuance costs.

27

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

12. Debt

	December 31,
	2016			2015
	(Millions)
Senior notes:
Issued November, 2012, interest at 2.500% payable semi-annually, due December, 2017	500			500
Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)	450			450
Issued March, 2014, interest at 2.700% payable semi-annually, due April, 2019	325			325
Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)	600			600
Issued September 2011, interest at 4.750% payable semiannually, due September 2021	500			500
Issued March, 2012, interest at 4.950% payable semi-annually, due April, 2022	350			350
Issued March, 2013, interest at 3.875% payable semi-annually, due March, 2023	500			500
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (a)	300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036	300			300
Issued September 2007, interest at 6.750% payable semiannually, due September 2037	450			450
Issued March, 2014, interest at 5.600% payable semi-annually, due April, 2044	400			400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semiannually, due May 2043	550			550
Credit facilities with financial institutions:
Revolving credit agreement terminated December, 2016, weighted average interest rate of 2.930% at December 31, 2015	—			96
Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019	195			375
Fair value adjustments related to interest rate swap fair value hedges (a)	24			26
Unamortized issuance costs	(23		)	(35		)
Unamortized discount	(14		)	(18		)
Total debt	5,407			5,669
Current maturities of long-term debt	500			—
Total long-term debt	$	4,907		$	5,669

(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $24 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt.

Credit Facilities with Financial Institutions

In May 2016, we entered into a second amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement (the DCP Midstream Amended and Restated Credit Agreement), which extended the maturity date from March 2017 to May 2019 and reduced the total borrowing capacity from $1.8 billion to $700 million. The DCP Midstream Amended and Restated Revolving Credit Agreement was terminated on December 30, 2016. In conjunction with the termination of the DCP Midstream Amended and Restated Revolving Credit Agreement, $10 million of unamortized issuance costs were included in interest expense.

28

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

In March 2015, we entered into a first amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement, which reduced the total borrowing capacity of the facility from $2.0 billion to $1.8 billion and revised the maturity date of the facility from May 2019 to March 2017. None of our physical assets were pledged as collateral for borrowings under this facility. The DCP Midstream Amended and Restated Revolving Credit Agreement was used to support our capital expansion program, for working capital requirements and other general corporate purposes, including acquisitions, as well as for letters of credit.

We have a $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% 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 0.45% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.

As of December 31, 2016, we had unused borrowing capacity of $1,031 million, net of $24 million of letters of credit, under the Amended and Restated Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnerships ability to incur incremental debt by $970 million as of December 31, 2016. Our borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.

The Amended and Restated 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 Amended and Restated 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.

Senior Notes and Junior Subordinated Notes

Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on the respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our credit agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

29

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

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

	Debt Maturities
	(Millions)
2017	$	500
2018	—
2019	970
2020	600
2021	500
Thereafter	2,850
	5,420
Fair value adjustments related to interest rate swap fair value hedges	24
Unamortized issuance costs	(23		)
Unamortized discount	(14		)
Total	$	5,407

13. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

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. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.

Commodity Price Risk

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.

Natural Gas Asset Based Trading and Marketing

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.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Commodity Cash Flow Hedges

In order for our natural gas storage facility 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 construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016.

Commodity 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 may 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. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our hedging programs 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 may use crude oil swaps to mitigate a portion of the commodity price risk exposure for 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. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations as trading and marketing (losses) gains, net.

NGL Proprietary Trading

Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments 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.

We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.

Interest Rate Risk

We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Credit Risk

Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

Contingent Credit Features

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

We have International Swaps and Derivatives 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 Amended and Restated 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.

• Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.

• 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 other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Amended and Restated Credit Agreement. As of December 31, 2016, we were not a party to any agreements that would trigger the cross-default provisions.

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, 2016, we had less than $1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may 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, 2016, we were not required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2016, the net liability position would be offset by contracts in a net asset position.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Collateral

As of December 31, 2016, we had cash deposits of $71 million, included in current assets in our consolidated balance sheet, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of December 31, 2016, we held cash of $5 million, included in other current liabilities in our consolidated balance sheet, related to cash postings by third parties and letters of credit of $38 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

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:

	December 31, 2016								December 31, 2015
	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
	(Millions)
Assets:
Commodity derivatives	$	47		$	—	$	47		$	175		$	(1	)	$	174
Liabilities:
Commodity derivatives	$	(92	)	$	—	$	(92	)	$	(81	)	$	—		$	(81	)

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

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Summarized Derivative Information

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

Balance sheet line item	December 31,   2016		December 31,   2015		Balance sheet line item	December 31,   2016			December 31,   2015
	(Millions)					(Millions)
Derivative assets not designated as hedging instruments:					Derivative liabilities not designated as hedging instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	42	$	156	Unrealized losses on derivative instruments — current	$	(91	)	$	(69	)
Unrealized gains on derivative instruments — long-term	5		19		Unrealized losses on derivative instruments — long-term	(1		)	(12		)
Total	$	47	$	175	Total	$	(92	)	$	(81	)

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, 2016:

	Interest Rate Derivatives			Commodity Derivatives			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)

(a) Relates to Discovery, an unconsolidated affiliate.

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, 2015:

	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)	$	(4	)	$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion (b)	1			—			—		1
Net deferred losses in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)

(a) Relates to Discovery, an unconsolidated affiliate.

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

For the years ended December 31, 2016 and 2015, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our consolidated statements of operations. For the years ended December 31, 2016 and 2015, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:

		Year Ended December 31,
Derivatives: Statements of Operations Line Item		2016			2015		2014
	(Millions)
Realized gains		$	116		$	73	$	45
Unrealized (losses) gains		(139		)	46		43
Trading and marketing (losses) gains, net		$	(23	)	$	119	$	88

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 derivative positions, as well as the number of outstanding contracts that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below.

	December 31, 2016
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long Position (MMBtu)
2017	(1,470,000	)	(44,981,850	)	(22,225,821	)	6,510,000
2018	(251,000	)	—		144,805		912,500
2019	(40,000	)	—		(2,203	)	—
2020	(50,000)		—		240,000		—

	December 31, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long  Position (MMBtu)
2016	(1,566,672	)	(25,059,414	)	(23,575,094	)	2,207,500
2017	(237,000	)	(7,387,500	)	(2,082,157	)	4,050,000
2018	—		—		120,000		—

14. Partnership Equity and Distributions

During the year ended December 31, 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of December 31, 2016, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

During the year ended December 31, 2015, we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and offering costs of less than $1 million.

In June 2014, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $500 million, which became effective on July 11, 2014. The shelf registration statement allows us to issue additional common units. In September 2014, we entered into an equity distribution agreement, or the 2014 equity distribution agreement, with a group of financial institutions as sales agents. The 2014 equity distribution 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 $500 million. During the year ended December 31, 2014, we issued 2,256,066 of our common units pursuant to the 2014 equity distribution agreement and received

35

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

proceeds of $119 million, net of commissions and accrued offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes.

In March 2014, we issued 14,375,000 common units to the public at $48.90 per unit. We received proceeds of $677 million, net of offering costs.

In March 2014, we issued 4,497,158 common units to DCP Midstream, LLC as partial consideration for certain transactions that closed in March 2014.

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 0.3% and limited partner interest of approximately 1.7% as of December 31, 2016. 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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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

The following table presents our cash distributions paid in 2016, 2015 and 2014:

Payment Date	Per Unit Distribution		Total Cash Distribution
	(Millions)
November 14, 2016	$	0.7800	$	120
August 12, 2016	$	0.7800	$	121
May 13, 2016	$	0.7800	$	121
February 12, 2016	$	0.7800	$	121
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86

15. Equity-Based Compensation

On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 Long-Term Incentive Plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and, together with the 2012 LTIP and the 2016 LTIP, the “LTIP”).  Any outstanding awards under the 2005 LTIP will remain outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards.  The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued.

On November 28, 2005, the board of directors of our General Partner adopted 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. The 2005 LTIP phantom units consist of a notional unit based on the value of the Partnership's common units. 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 the 2012 LTIP (the "2012 LTIP") for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provided for the grant of phantom units and DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Enbridge. 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 under the LTIPs are subject to cliff vesting.

Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the value of common shares or units of Phillips 66, Enbridge and the Partnership. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The DCP Midstream LTIP is administered by the compensation committee of DCP Midstream, LLC's board of directors. All awards are subject to cliff vesting.

37

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units on the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, 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.

Equity-based compensation expense was $18 million, $8 million and $14 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units:

	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2016 (millions)		Estimated Forfeiture Rate	Weighted-Average Remaining Vesting (years)
DCP Midstream LTIP:
Strategic Performance Units (SPUs)	3	$	6	0%-11%	2
Phantom Units	1-3	$	5	0%-11%	2

Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our board of directors. The DERs are paid in cash at the end of the performance period. The following tables presents information related to SPUs:

	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	230,900		$	39.30
Granted	116,790		$	54.05
Forfeited	(13,828	)	$	40.75
Vested (a)	(114,499	)	$	37.72
Outstanding at December 31, 2014	219,363		$	47.89
Granted	111,930		$	43.25
Forfeited	(29,283	)	$	48.02
Vested (b)	(93,551	)	$	41.02
Outstanding at December 31, 2015	208,459		$	48.46
Granted	131,610		$	45.31
Forfeited	(8,463	)	$	46.27
Vested (c)	(98,295	)	$	54.05
Outstanding at December 31, 2016	233,311		$	44.41	$	45.86
Expected to vest	219,844		$	44.35	$	45.98

(a) The 2012 grants vested at 115%.

(b) The 2013 grants vested at 115%.

(c) The 2014 grants vested at 130%.

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DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiture rate and achievement of performance targets.

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

	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	114,499	$	7	$	8
Vested or paid in cash in 2015	93,551	$	4	$	7
Vested or paid in cash in 2016	98,295	$	7	$	4

Phantom Units -The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units:

	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	207,522		$	40.18
Granted	122,650		$	53.73
Forfeited	(11,130	)	$	41.96
Vested	(147,840	)	$	42.10
Outstanding at December 31, 2014	171,202		$	48.11
Granted	147,540		$	47.84
Forfeited	(17,400	)	$	48.40
Vested	(96,974	)	$	44.00
Outstanding at December 31, 2015	204,368		$	49.85
Granted	132,870		$	45.33
Forfeited	(3,240	)	$	48.62
Vested	(126,681	)	$	50.13
Outstanding at December 31, 2016	207,317		$	46.80	$	45.97
Expected to vest	185,785		$	46.72	$	45.90

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

	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	147,840	$	5	$	5
Vested or paid in cash in 2015	96,974	$	3	$	5
Vested or paid in cash in 2016	126,681	$	4	$	5

39

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

16. Benefits

We do not have our own employees. The employees supporting our operations are employees of DCP Midstream, LLC, for which we incur charges under the Services Agreement. All DCP Midstream, LLC employees who have reached the age of 18 and work at least 20 hours per week are eligible for participation in the 401(k) and retirement plan, to which a range of 4% to 7% of each eligible employee’s qualified earnings is contributed to the retirement plan, based on years of service. Effective on January 1, 2015, DCP Midstream, LLC added an automatic enrollment feature in the 401(k) plan, meaning all new employees are enrolled at a 6% contribution level. Employees can opt out of these contribution level or change it at any time. Additionally, DCP Midstream, LLC matches employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During the years ended December 31, 2016, 2015 and 2014, we expensed plan contributions of $29 million, $32 million and $30 million, respectively.

DCP Midstream, LLC offers certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf.

17. 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 method. Dilutive potential units include outstanding awards under the LTIP. The dilutive effect of unit-based awards was 1,105, 7,038 and 10,574 equivalent units during the years ended December 31, 2016, 2015 and 2014 respectively.

18. 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. We owned a corporation that filed its own federal, foreign and state corporate income tax returns. During the year ended December 31, 2016, we elected to convert the corporation to a limited liability company for federal income tax purposes. The income tax (expense) benefit related to this corporation is included in our income tax (expense) benefit, along with state and local taxes of the limited liability entities.

40

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Income tax (expense) benefit consists of the following:

	Year Ended December 31,
	2016			2015		2014
	(Millions)
Current:
Federal income tax expense	$	(19	)	$	—	$	—
State income tax expense	(2		)	—		(2		)
Deferred:
Federal income tax (expense) benefit	(22		)	97		—
State income tax (expense) benefit	(3		)	5		(9		)
Total income tax (expense) benefit	$	(46	)	$	102	$	(11	)

Deferred income tax assets and liabilities consisted of the following:

	December 31,
	2016			2015
	(Millions)
Deferred income tax assets:
Net operating loss	$	—		$	58
Total deferred income tax assets	—			58
Deferred income tax liabilities:
Property, plant and equipment and intangibles - federal	—			(35		)
Property, plant and equipment and intangibles - state	(28		)	(26		)
Total deferred income tax liabilities	(28		)	(61		)
Net deferred income tax liabilities	(28		)	(3		)
Deferred income tax assets, net - noncurrent	—			23
Deferred income tax liabilities, net - noncurrent	(28		)	(26		)
Net deferred income tax liabilities	$	(28	)	$	(3	)

The state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we recorded a reduction to our net federal deferred tax asset of $58 million resulting from the conversion of our corporation to a limited liability company.

As of December 31 2015, our federal net operating losses were $163 million. The net operating losses were fully utilized upon the conversion of our corporation to a limited liability company during the year ended December 31, 2016.

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, primarily Texas. The State of Texas imposes a margin tax that is assessed at 0.75%, 0.75%, and 0.95%, of taxable margin apportioned to Texas for the years ended December 31, 2016, 2015 and 2014, respectively.

41

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

19. Commitments and Contingent Liabilities

Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our results of operations, financial position, or cash flow.

In January 2016, we reached a settlement with a large producer in the DJ basin and received a cash payment of $89 million, a dedication of a portion of the producer’s production in the DJ Basin under a life of lease agreement and a 15 year dedication of natural gas liquids from the producer and its affiliates to the Sand Hills pipeline in the Delaware basin of the Permian region. The cash consideration was received in February 2016, and we recorded other income, net of $2 million in legal fees, in the consolidated statement of operations for the year December 31, 2016.

Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6) 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 with similar types of operations.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, 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 laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous 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, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus (i) from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. Failure to comply with these various health, safety and environmental 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 existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.

42

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

We make expenditures in connection with environmental matters as part of our normal operations. As of December 31, 2016 and December 31, 2015, environmental liabilities included in our combined balance sheets as other current liabilities were $4 million and $3 million, respectively. As of December 31, 2016 and 2015, environmental liabilities included in our combined balance sheets as other long-term liabilities was $9 million.

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 $37 million, $34 million, and $31 million for the years ended December 31, 2016, 2015, and 2014, 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, 2016:

	(Millions)
2017	$	61
2018	37
2019	35
2020	29
2021	21
Thereafter	42
Total minimum rental payments	$	225

20. Restructuring Costs

In April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain operational and corporate positions, as part of their ongoing effort to create efficiencies, reduce costs and transform our business. As a result of this headcount reduction, we recorded one-time employee termination costs of approximately $13 million, which are included in restructuring costs in our consolidated statements of operations for the year ended December 31, 2016.

As of December 31, 2016, approximately $1 million of the $13 million restructuring charge incurred is included in other current liabilities. Additionally, we expect to incur further severance costs of less than $1 million related to this phase of our restructuring plan. The severance costs estimate could change based on the number of employees that work through the required service period and the timing of those departures.

In January 2015, we announced the initial phase of this cost reduction plan, which involved the elimination of certain corporate employee positions. As a result, we recorded employee termination costs of approximately $11 million, all of which were paid during the year ended December 31, 2015, and are included in restructuring costs in the consolidated statement of operations for the year ended December 31, 2015.

21. Business Segments

Concurrent with the completion of the Transaction in the first quarter of 2017, management reevaluated our reportable segments and determined that our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing. Segment information for prior periods has been retrospectively adjusted to furnish comparative information similar to the pooling method to reflect these reportable segments. 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. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment.

Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering and selling condensate. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of

43

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminations column.

Year Ended December 31, 2016:

	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,490		$	6,186		$	—		$	(3,783	)	$	6,893
Gross margin (a)	$	1,227		$	205		$	—		$	—		$	1,432
Operating and maintenance expense	(611		)	(43		)	(16		)	—			(670		)
Depreciation and amortization expense	(344		)	(15		)	(19		)	—			(378		)
General and administrative expense	(14		)	(9		)	(269		)	—			(292		)
Other income (expense), net	73			(5		)	(3		)	—			65
Earnings from unconsolidated affiliates	73			209			—			—			282
Interest expense, net	—			—			(321		)	—			(321		)
Gain on sale of assets, net	19			16			—			—			35
Restructuring costs	—			—			(13		)	—			(13		)
Income tax expense	—			—			(46		)	—			(46		)
Net income (loss)	$	423		$	358		$	(687	)	$	—		$	94
Net income attributable to non-controlling interests	(6		)	—			—			—			(6		)
Net income (loss) attributable to partners	$	417		$	358		$	(687	)	$	—		$	88
Non-cash derivative mark-to-market (b)	$	(119	)	$	(20	)	$	—		$	—		$	(139	)
Non-cash lower of cost or market adjustments	$	—		$	3		$	—		$	—		$	3
Capital expenditures	$	107		$	10		$	27		$	—		$	144
Investments in unconsolidated affiliates, net	$	1		$	52		$	—		$	—		$	53

44

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Year Ended December 31, 2015:

	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,910		$	6,487		$	—		$	(3,967	)	$	7,430
Gross margin (a)	$	1,213		$	236		$	—		$	—		$	1,449
Operating and maintenance expense	(668		)	(49		)	(15		)	—			(732		)
Depreciation and amortization expense	(343		)	(16		)	(18		)	—			(377		)
General and administrative expense	(22		)	(11		)	(248		)	—			(281		)
Other expense, net	(1		)	(8		)	(1		)	—			(10		)
Asset impairment	(876		)	(9		)	(27		)	—			(912		)
Earnings from unconsolidated affiliates	54			130			—			—			184
Interest expense, net	—			—			(320		)	—			(320		)
Gain on sale of assets, net	42			—			—			—			42
Restructuring costs	—			—			(11		)	—			(11		)
Income tax benefit	—			—			102			—			102
Net income (loss)	$	(601	)	$	273		$	(538	)	$	—		$	(866	)
Net income attributable to non-controlling interests	(5		)	—			—			—			(5		)
Net income (loss) attributable to partners	$	(606	)	$	273		$	(538	)	$	—		$	(871	)
Non-cash derivative mark-to-market (b)	$	47		$	(1	)	$	—		$	—		$	46
Non-cash lower of cost or market adjustments	$	—		$	8		$	—		$	—		$	8
Capital expenditures	$	729		$	52		$	30		$	—		$	811
Investments in unconsolidated affiliates, net	$	15		$	49		$	—		$	—		$	64

45

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

Year Ended December 31, 2014:

	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	9,873		$	12,649		$	—		$	(8,497	)	$	14,025
Gross margin (a)	$	1,971		$	226		$	—		$	—		$	2,197
Operating and maintenance expense	(725		)	(44		)	(4		)	—			(773		)
Depreciation and amortization expense	(315		)	(17		)	(16		)	—			(348		)
General and administrative expense	(27		)	(14		)	(236		)	—			(277		)
Other expense, net	(5		)	—			(2		)	—			(7		)
Asset impairment	(18		)	—			—			—			(18		)
Earnings from unconsolidated affiliates	5			77			—			—			82
Interest expense, net	—			—			(287		)	—			(287		)
Loss on sale of assets, net	(7		)	—			—			—			(7		)
Income tax expense	—			—			(11		)	—			(11		)
Net income (loss)	$	879		$	228		$	(556	)	$	—		$	551
Net income attributable to non-controlling interests	(4		)	—			—			—			(4		)
Net income (loss) attributable to partners	$	875		$	228		$	(556	)	$	—		$	547
Non-cash derivative mark-to-market (b)	$	39		$	4		$	—		$	—		$	43
Non-cash lower of cost or market adjustments	$	—		$	24		$	—		$	—		$	24
Capital expenditures	$	1,272		$	62		$	50		$	—		$	1,384
Investments in unconsolidated affiliates, net	$	75		$	86		$	—		$	—		$	161

	December 31,
	2016		2015
	(Millions)
Segment long-term assets:
Gathering and Processing	$	9,053	$	9,431
Logistics and Marketing	3,278		3,339
Other (c)	286		311
Total long-term assets	12,617		13,081
Current assets	994		804
Total assets	$	13,611	$	13,885

(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Gross margin is viewed as a non-GAAP financial 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) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.

(c) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

46

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

22. Supplemental Cash Flow Information

	Year Ended December 31,
	2016			2015			2014
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	306		$	293		$	274
Cash paid for income taxes, net of income tax refunds	$	2		$	3		$	4
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	27		$	35		$	145
Other non-cash changes in property, plant and equipment	$	(3	)	$	(19	)	$	27
Contribution of assets from our predecessor	$	—		$	1,500		$	—

23. Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows (millions, except per unit amounts):

2016	First			Second			Third			Fourth			Year Ended December 31, 2016
Total operating revenues	$	1,464		$	1,623		$	1,823		$	1,983		$	6,893
Operating income (loss)	$	80		$	(12	)	$	92		$	19		$	179
Net income (loss)	$	65		$	(21	)	$	89		$	(39	)	$	94
Net income attributable to non-controlling interests	$	—		$	(1	)	$	—		$	(5	)	$	(6	)
Net income attributable to partners	$	65		$	(22	)	$	89		$	(44	)	$	88
Net loss attributable to predecessor operations	$	(7	)	$	(67	)	$	(31	)	$	(119	)	$	(224	)
Net income allocable to limited partners	$	41		$	14		$	89		$	44		$	188
Basic and diluted net income per limited partner unit	$	0.36		$	0.12		$	0.78		$	0.38		$	1.64

2015	First			Second			Third			Fourth			Year Ended December 31, 2015
Total operating revenues	$	2,020		$	1,849		$	1,870		$	1,691		$	7,430
Operating income (loss)	$	40		$	(463	)	$	57		$	(466	)	$	(832	)
Net (loss) income	$	(17	)	$	(491	)	$	24		$	(382	)	$	(866	)
Net income attributable to non-controlling interests	$	—		$	—		$	(1	)	$	(4	)	$	(5	)
Net income attributable to partners	$	(17	)	$	(491	)	$	23		$	(386	)	$	(871	)
Net loss attributable to predecessor operations	$	(86	)	$	(489	)	$	(48	)	$	(476	)	$	(1,099	)
Net income (loss) allocable to limited partners	$	38		$	(33	)	$	40		$	59		$	104
Basic and diluted net income (loss) per limited partner unit	$	0.33		$	(0.29	)	$	0.35		$	0.51		$	0.91

24. 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, 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, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt 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.

47

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Balance Sheet
	December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			792			—			792
Inventories	—		—			72			—			72
Other	—		—			129			—			129
Total current assets	—		—			994			—			994
Property, plant and equipment, net	—		—			9,069			—			9,069
Goodwill and intangible assets, net	—		—			373			—			373
Advances receivable — consolidated subsidiaries	2,953		2,760			—			(5,713		)	—
Investments in consolidated subsidiaries	3,868		6,587			—			(10,455		)	—
Investments in unconsolidated affiliates	—		—			2,969			—			2,969
Other long-term assets	—		—			206			—			206
Total assets	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	1,051		$	—		$	1,123
Current maturities of long-term debt	—		500			—			—			500
Advances payable — consolidated subsidiaries	—		—			5,713			(5,713		)	—
Long-term debt	—		4,907			—			—			4,907
Other long-term liabilities	—		—			228			—			228
Total liabilities	—		5,479			6,992			(5,713		)	6,758
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	6,821		3,871			6,592			(10,455		)	6,829
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	6,821		3,868			6,587			(10,455		)	6,821
Non-controlling interests	—		—			32			—			32
Total equity	6,821		3,868			6,619			(10,455		)	6,853
Total liabilities and equity	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611

48

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	3		$	—		$	3
Accounts receivable, net	—		—			544			—			544
Inventories	—		—			51			—			51
Other	—		—			206			—			206
Total current assets	—		—			804			—			804
Property, plant and equipment, net	—		—			9,428			—			9,428
Goodwill and intangible assets, net	—		—			391			—			391
Advances receivable — consolidated subsidiaries	3,436		3,353			—			(6,789		)	—
Investments in consolidated subsidiaries	3,623		6,011			—			(9,634		)	—
Investments in unconsolidated affiliates	—		—			2,992			—			2,992
Other long-term assets	—		—			270			—			270
Total assets	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	827		$	—		$	899
Advances payable — consolidated subsidiaries			—			6,789			(6,789		)	—
Long-term debt	—		5,669			—			—			5,669
Other long-term liabilities	—		—			225			—			225
Total liabilities	—		5,741			7,841			(6,789		)	6,793
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	7,059		3,626			6,016			(9,634		)	7,067
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	7,059		3,623			6,011			(9,634		)	7,059
Non-controlling interests	—		—			33			—			33
Total equity	7,059		3,623			6,044			(9,634		)	7,092
Total liabilities and equity	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885

49

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	6,269		$	—		$	6,269
Transportation, processing and other	—		—			647			—			647
Trading and marketing losses, net	—		—			(23		)	—			(23		)
Total operating revenues	—		—			6,893			—			6,893
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			5,461			—			5,461
Operating and maintenance expense	—		—			670			—			670
Depreciation and amortization expense	—		—			378			—			378
General and administrative expense	—		—			292			—			292
Other income, net	—		—			(65		)	—			(65		)
Restructuring costs	—		—			13						13
Gain on sale of assets, net	—		—			(35		)	—			(35		)
Total operating costs and expenses	—		—			6,714			—			6,714
Operating income	—		—			179			—			179
Interest expense, net	—		(321		)	—			—			(321		)
Income from consolidated subsidiaries	88		409			—			(497		)	—
Earnings from unconsolidated affiliates	—		—			282			—			282
Income before income taxes	88		88			461			(497		)	140
Income tax expense	—		—			(46		)	—			(46		)
Net income	88		88			415			(497		)	94
Net income attributable to non-controlling interests	—		—			(6		)	—			(6		)
Net income attributable to partners	$	88	$	88		$	409		$	(497	)	$	88

	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	88	$	88	$	415		$	(497	)	$	94
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		—		—			—			—
Other comprehensive income from consolidated subsidiaries	—		—		—			—			—
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	88		88		415			(497		)	94
Total comprehensive income attributable to non-controlling interests	—		—		(6		)	—			(6		)
Total comprehensive income attributable to partners	$	88	$	88	$	409		$	(497	)	$	88

50

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—		$	—		$	6,779		$	—	$	6,779
Transportation, processing and other	—			—			532			—		532
Trading and marketing gains, net	—			—			119			—		119
Total operating revenues	—			—			7,430			—		7,430
Operating costs and expenses:
Purchases of natural gas and NGLs	—			—			5,981			—		5,981
Operating and maintenance expense	—			—			732			—		732
Depreciation and amortization expense	—			—			377			—		377
General and administrative expense	—			—			281			—		281
Asset impairments	—			—			912			—		912
Other expense, net	—			—			10			—		10
Restructuring costs	—			—			11			—		11
Gain on sale of assets, net	—			—			(42		)	—		(42		)
Total operating costs and expenses	—			—			8,262			—		8,262
Operating loss	—			—			(832		)	—		(832		)
Interest expense, net	—			(320		)	—			—		(320		)
Loss from consolidated subsidiaries	(871		)	(551		)	—			1,422		—
Earnings from unconsolidated affiliates	—			—			184			—		184
Loss before income taxes	(871		)	(871		)	(648		)	1,422		(968		)
Income tax benefit	—			—			102			—		102
Net loss	(871		)	(871		)	(546		)	1,422		(866		)
Net income attributable to non-controlling interests	—			—			(5		)	—		(5		)
Net loss attributable to partners	$	(871	)	$	(871	)	$	(551	)	$	1,422	$	(871	)

	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net loss	$	(871	)	$	(871	)	$	(546	)	$	1,422		$	(866	)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			1			—			—			1
Other comprehensive income from consolidated subsidiaries	1			—			—			(1		)	—
Total other comprehensive income	1			1			—			(1		)	1
Total comprehensive loss	(870		)	(870		)	(546		)	1,421			(865		)
Total comprehensive loss attributable to non-controlling interests	—			—			(5		)	—			(5		)
Total comprehensive loss attributable to partners	$	(870	)	$	(870	)	$	(551	)	$	1,421		$	(870	)

51

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	13,420		$	—		$	13,420
Transportation, processing and other	—		—			517			—			517
Trading and marketing gains, net	—		—			88			—			88
Total operating revenues	—		—			14,025			—			14,025
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			11,828			—			11,828
Operating and maintenance expense	—		—			773			—			773
Depreciation and amortization expense	—		—			348			—			348
General and administrative expense	—		—			277			—			277
Asset impairments	—		—			18			—			18
Other expense, net	—		—			7			—			7
Loss on sale of assets, net	—		—			7			—			7
Total operating costs and expenses	—		—			13,258			—			13,258
Operating income	—		—			767			—			767
Interest expense, net	—		(287		)	—			—			(287		)
Earnings from unconsolidated affiliates	—		—			82			—			82
Income from consolidated subsidiaries	547		834			—			(1,381		)	—
Income before income taxes	547		547			849			(1,381		)	562
Income tax expense	—		—			(11		)	—			(11		)
Net income	547		547			838			(1,381		)	551
Net income attributable to non-controlling interests	—		—			(4		)	—			(4		)
Net income attributable to partners	$	547	$	547		$	834		$	(1,381	)	$	547

	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	547	$	547	$	838		$	(1,381	)	$	551
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		2		—			—			2
Other comprehensive income from consolidated subsidiaries	2		—		—			(2		)	—
Total other comprehensive income	2		2		—			(2		)	2
Total comprehensive income	549		549		838			(1,383		)	553
Total comprehensive income attributable to non-controlling interests	—		—		(4		)	—			(4		)
Total comprehensive income attributable to partners	$	549	$	549	$	834		$	(1,383	)	$	549

52

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(305	)	$	950		$	—		$	645
INVESTING ACTIVITIES:
Intercompany transfers	483			585			—			(1,068		)	—
Capital expenditures	—			—			(144		)	—			(144		)
Investments in unconsolidated affiliates, net	—			—			(53		)	—			(53		)
Proceeds from sale of assets	—			—			163			—			163
Net cash provided by (used in) investing activities	483			585			(34		)	(1,068		)	(34		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(1,068		)	1,068			—
Proceeds from long-term debt	—			3,353			—			—			3,353
Payments of long-term debt	—			(3,628		)	—			—			(3,628		)
Payments of deferred financing costs	—			(5		)	—			—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			157			—			157
Distributions to limited partners and general partner	(483		)	—			—			—			(483		)
Distributions to non-controlling interests	—			—			(7		)	—			(7		)
Net cash used in financing activities	(483		)	(280		)	(918		)	1,068			(613		)
Net change in cash and cash equivalents	—			—			(2		)	—			(2		)
Cash and cash equivalents, beginning of period	—			—			3			—			3
Cash and cash equivalents, end of period	$	—		$	—		$	1		$	—		$	1

53

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(311	)	$	753		$	—		$	442
INVESTING ACTIVITIES:
Intercompany transfers	(1,049		)	1,283			—			(234		)	—
Capital expenditures	—			—			(811		)	—			(811		)
Investments in unconsolidated affiliates, net	—			—			(64		)	—			(64		)
Proceeds from sale of assets	—			—			164			—			164
Net cash (used in) provided by investing activities	(1,049		)	1,283			(711		)	(234		)	(711		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(234		)	234			—
Proceeds from long-term debt	—			7,216			—			—			7,216
Payments of long-term debt	—			(7,196		)	—			—			(7,196		)
Payments of commercial paper, net	—			(1,012		)	—			—			(1,012		)
Payment of deferred financing costs	—			(4		)	—			—			(4		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Net change in advances to predecessor from DCP Midstream, LLC	1,500			—			197			—			1,697
Distributions to limited partners and general partner	(482		)	—			—			—			(482		)
Distributions to non-controlling interests	—						(5		)	—			(5		)
Net cash provided by (used in) financing activities	1,049			(996		)	(42		)	234			245
Net change in cash and cash equivalents	—			(24		)	—			—			(24		)
Cash and cash equivalents, beginning of period	—			24			3			—			27
Cash and cash equivalents, end of period	$	—		$	—		$	3		$	—		$	3

54

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2014
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(271	)	$	1,088		$	—		$	817
INVESTING ACTIVITIES:
Intercompany transfers	(581		)	(141		)	—			722			—
Capital expenditures	—			—			(1,384		)	—			(1,384		)
Investments in unconsolidated affiliates, net	—			—			(161		)	—			(161		)
Proceeds from sale of assets	—			—			30			—			30
Net cash used in investing activities	(581		)	(141		)	(1,515		)	722			(1,515		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			722			(722		)	—
Proceeds from long-term debt	—			719			—			—			719
Payments of issuance of commercial paper, net	—			(288		)	—			—			(288		)
Payment of deferred financing costs	—			(12		)	—			—			(12		)
Proceeds from issuance of common units, net of offering costs	1,001			—			—			—			1,001
Distributions to limited partners and general partner	(420		)	—			—			—			(420		)
Distributions to non-controlling interests	—			—			(5		)	—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			(301		)	—			(301		)
Net cash provided by financing activities	581			419			416			(722		)	694
Net change in cash and cash equivalents	—			7			(11		)	—			(4		)
Cash and cash equivalents, beginning of year	—			17			14			—			31
Cash and cash equivalents, end of year	$	—		$	24		$	3		$	—		$	27

25. Subsequent Events

On December 30, 2016, we entered into a Contribution Agreement with DCP Midstream, LLC and DCP Midstream Operating, LP. The Transaction closed effective January 1, 2017. For additional information regarding the Transaction, see Note 4 - Acquisitions.

Effective January 11, 2017, we changed our name to "DCP Midstream, LP" from "DCP Midstream Partners, LP" (the Name Change").

In connection with the Name Change, the ticker symbol for our common units representing limited partner interests listed on the NYSE changed from “DPM” to “DCP” effective at the open of the NYSE on January 23, 2017.

On January 26, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on February 14, 2017 to unitholders of record on February 7, 2017, except that the owners of the Partnership's General Partner will receive distributions on the units issued on January 1, 2017 beginning with the first quarter 2017 declared distribution.

55

DCP MIDSTREAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2016, 2015 and 2014 (Continued)

In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

On April 25, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on May 15, 2017 to unitholders of record on May 9, 2017.

On May 17, 2017, we announced the planned divestiture of our Douglas gathering system in Wyoming, which includes approximately 1,500 miles of gathering lines for approximately $128 million, subject to customary closing adjustments. The transaction is expected to close on or before the end of the second quarter.

56