SEC Filing | DCP Midstream, LP

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

(Amendment No. 1)

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): December 30, 2016

DCP MIDSTREAM, LP

(Exact name of registrant as specified in its charter)



Delaware	001-32678	03-0567133
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

370 17th Street, Suite 2500

Denver, Colorado 80202

(Address of principal executive offices) (Zip Code)

(303) 595-3331

(Registrant’s telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)


¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)


¨	Pre-commencement communications pursuant to Rule 14d-2(b) under Exchange Act (17 CFR 240.14d-2(b))


¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

This Current Report on Form 8-K/A amends the Current Report on Form 8-K filed by DCP Midstream, LP (the “Partnership”) on January 6, 2017 (the “Initial Form 8-K”) to provide information that was not required at the time of filing the Initial Form 8-K. The Partnership is hereby amending Item 9.01 of the Initial Form 8-K to provide audited financial statements of The DCP Midstream Business that was contributed to the Partnership as further described in the Initial Form 8-K (the “Transaction”) and unaudited pro forma financial statements of the Partnership giving effect to the Transaction.

Item 9.01 Financial Statements and Exhibits.


(a)	Financial statements of businesses acquired.

Audited Combined Financial Statements of The DCP Midstream Business as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016, filed as Exhibit 99.2 hereto and incorporated herein by reference.


(b)	Pro forma financial information.

The unaudited pro forma condensed consolidated financial statements of DCP Midstream, LP as of December 31, 2016 and for each of the three years in the period ended December 31, 2016, furnished as Exhibit 99.3 hereto and incorporated herein by reference.

(d) Exhibits



Exhibit No.	Description
2.1*	Contribution Agreement, dated December 30, 2016, by and among DCP Midstream, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP.
3.1*	Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated January 1, 2017.
4.1*	Indenture, dated as of August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase Manhattan Bank.
4.2*	First Supplemental Indenture, dated August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase Manhattan Bank (attached as Exhibit 4.1 to DCP Midstream, LLC’s Current Report on Form 8-K (File No. 000-31095) filed with the SEC on August 16, 2000).
4.3*	Fifth Supplemental Indenture, dated as of October 27, 2006, by and between Duke Energy Field Services, LLC and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.4*	Sixth Supplemental Indenture, dated September 17, 2007, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.5*	Eighth Supplemental Indenture, dated February 24, 2009, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.6*	Ninth Supplemental Indenture, dated March 11, 2010, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.7*	Tenth Supplemental Indenture, dated September 19, 2011, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.8*	Eleventh Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.9*	Twelfth Supplemental Indenture, dated January 1, 2017, by and among DCP Midstream Operating, LP (as successor to DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC)), DCP Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.10*	Indenture, dated as of May 21, 2013, by and between DCP Midstream, LLC and the Bank of New York Mellon Trust Company, N.A.
4.11*	First Supplemental Indenture, dated May 21, 2013, by and between DCP Midstream, LLC and the Bank of New York Mellon Trust Company, N.A.
4.12*	Second Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A.
10.1*	Services and Employee Secondment Agreement, dated January 1, 2017, by and between DCP Services, LLC and DCP Midstream Partners, LP.
23.1	Consent of Deloitte & Touche LLP on The DCP Midstream Business Combined Financial Statements as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016.
99.1**	Press Release, dated January 4, 2017.
99.2	Audited Combined Financial Statements of The DCP Midstream Business as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016.
99.3	Unaudited pro forma condensed consolidated financial statements of DCP Midstream, LP as of December 31, 2016 and for each of the three years in the period ended December 31, 2016.

* Previously filed

** Previously furnished

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: March 15, 2017



DCP MIDSTREAM, LP

By:	DCP MIDSTREAM GP, LP,
	its General Partner

	By:	DCP MIDSTREAM GP, LLC,
		its General Partner

		By:	/s/ Sean P. O'Brien
		Name:	Sean P. O'Brien
		Title:	Group Vice President and Chief Financial Officer

EXHIBIT INDEX




Exhibit No.	Description
2.1*	Contribution Agreement, dated December 30, 2016, by and among DCP Midstream, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP.
3.1*	Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated January 1, 2017.
4.1*	Indenture, dated as of August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase Manhattan Bank.
4.2*	First Supplemental Indenture, dated August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase Manhattan Bank (attached as Exhibit 4.1 to DCP Midstream, LLC’s Current Report on Form 8-K (File No. 000-31095) filed with the SEC on August 16, 2000).
4.3*	Fifth Supplemental Indenture, dated as of October 27, 2006, by and between Duke Energy Field Services, LLC and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.4*	Sixth Supplemental Indenture, dated September 17, 2007, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.5*	Eighth Supplemental Indenture, dated February 24, 2009, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.6*	Ninth Supplemental Indenture, dated March 11, 2010, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.7*	Tenth Supplemental Indenture, dated September 19, 2011, by and between DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.8*	Eleventh Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.9*	Twelfth Supplemental Indenture, dated January 1, 2017, by and among DCP Midstream Operating, LP (as successor to DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC)), DCP Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank).
4.10*	Indenture, dated as of May 21, 2013, by and between DCP Midstream, LLC and the Bank of New York Mellon Trust Company, N.A.
4.11*	First Supplemental Indenture, dated May 21, 2013, by and between DCP Midstream, LLC and the Bank of New York Mellon Trust Company, N.A.
4.12*	Second Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A.
10.1*	Services and Employee Secondment Agreement, dated January 1, 2017, by and between DCP Services, LLC and DCP Midstream Partners, LP.
23.1	Consent of Deloitte & Touche LLP on The DCP Midstream Business Combined Financial Statements as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016.
99.1**	Press Release, dated January 4, 2017.
99.2	Audited Combined Financial Statements of The DCP Midstream Business as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016.
99.3	Unaudited pro forma condensed consolidated financial statements of DCP Midstream, LP as of December 31, 2016 and for each of the three years in the period ended December 31, 2016.

* Previously filed

** Previously furnished

Exhibit

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statement Nos. 333-142271 and 333-211905 on Form S-8 of DCP Midstream, LP and Registration Statement Nos. 333-182642, 333-196939 and 333-203588 on Form S-3 of DCP Midstream, LP of our report dated March 15, 2017, relating to the combined financial statements of the DCP Midstream Business (which report expresses an unmodified opinion and includes an other-matter paragraph referring to the preparation of the combined financial statements of the DCP Midstream Business from the separate records maintained by DCP Midstream, LLC), appearing in this Current Report on Form 8-K/A of DCP Midstream, LP dated March 15, 2017.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 15, 2017

Exhibit

Exhibit 99.2

Combined Financial Statements of

The DCP Midstream Business

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

TABLE OF CONTENTS



	Page

Independent Auditors' Report
Combined Balance Sheets	1
Combined Statements of Operations	2
Combined Statements of Comprehensive (Loss) Income	3
Combined Statements of Changes in Net Parent Equity	4
Combined Statements of Cash Flows	5
Notes to the Combined Financial Statements	6

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of

DCP Midstream GP, LLC

Denver, Colorado

We have audited the accompanying combined financial statements of the DCP Midstream Business (the "Business"), which comprise the combined balance sheets as of December 31, 2016 and 2015, and the related combined statements of operations, comprehensive (loss) income, changes in net parent equity, and cash flows for each of the three years in the period ended December 31, 2016, and the related notes to the combined financial statements.

Management's Responsibility for the Combined Financial Statements

Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Business's preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Business' internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the DCP Midstream Business 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 accordance with accounting principles generally accepted in the United States of America.

Other Matter

The accompanying combined financial statements have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Business had been operated as an unaffiliated company.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 15, 2017

The DCP Midstream Business

COMBINED BALANCE SHEETS



	December 31,			December 31,
	2016			2015
	(millions)
ASSETS
Current assets:
Cash and cash equivalents	$	418		$	1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $4 and $3 million, respectively	590			376
Affiliates	162			90
Other	6			20
Inventories	28			8
Unrealized gains on derivative instruments	63			101
Other	77			48
Total current assets	1,344			644
Property, plant and equipment, net	5,797			5,952
Investments in unconsolidated affiliates	1,494			1,500
Intangible assets, net	34			37
Goodwill	164			170
Unrealized gains on derivative instruments	5			20
Deferred income tax asset	—			23
Other long-term assets	189			219
Total assets	$	9,027		$	8,565
LIABILITIES AND NET PARENT EQUITY
Current liabilities:
Accounts payable:
Trade	$	569		$	382
Affiliates	139			117
Imbalance payable	10			25
Unrealized losses on derivative instruments	99			101
Accrued interest	54			53
Accrued taxes	30			26
Accrued wages and benefits	72			67
Other	75			75
Total current liabilities	1,048			846
Deferred income tax liability	22			18
Long-term debt	3,157			3,245
Unrealized losses on derivative instruments	1			21
Other long-term liabilities	161			148
Total liabilities	4,389			4,278
Commitments and contingent liabilities
Equity:
Parent equity	4,640			4,289
Accumulated other comprehensive loss	(2		)	(2		)
Total net parent equity	4,638			4,287
Total liabilities and net parent equity	$	9,027		$	8,565

See accompanying notes to combined financial statements.

The DCP Midstream Business

COMBINED STATEMENTS OF OPERATIONS



	Year Ended December 31,
	2016			2015			2014
	(millions)
Operating revenues:
Sales of natural gas and petroleum products	$	4,969		$	5,530		$	10,427
Sales of natural gas and petroleum products - affiliates	1,052			826			2,208
Transportation, processing and other	385			276			252
Transportation, processing and other - affiliates	5			3			12
Trading and marketing (losses) gains, net	(16		)	67			52
Trading and marketing gains (losses), net - affiliates	13			(33		)	(118		)
Total operating revenues	6,408			6,669			12,833
Operating costs and expenses:
Purchases of natural gas and petroleum products	4,164			4,424			8,838
Purchases of natural gas and petroleum products - affiliates	1,196			1,330			2,542
Transportation and other fees - affiliates	167			118			96
Operating and maintenance	487			518			558
Depreciation and amortization	256			257			238
Asset impairments	—			830			18
General and administrative	204			196			213
Loss (gain) on sale of assets, net	12			(42		)	7
Restructuring costs	13			11			—
Other (income) and expense, net	(72		)	6			4
Total operating costs and expenses	6,427			7,648			12,514
Operating (loss) income	(19		)	(979		)	319
Earnings from unconsolidated affiliates	68			11			7
Interest expense, net	(227		)	(228		)	(201		)
(Loss) income before income taxes	(178		)	(1,196		)	125
Income tax (expense) benefit	(46		)	97			(5		)
Net (loss) income	$	(224	)	$	(1,099	)	$	120

See accompanying notes to combined financial statements.

The DCP Midstream Business

COMBINED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME



	Year Ended December 31,
	2016			2015			2014
	(millions)
Net (loss) income	$	(224	)	$	(1,099	)	$	120
Other comprehensive income	—			—			—
Total comprehensive (loss) income	$	(224	)	$	(1,099	)	$	120

See accompanying notes to combined financial statements.

The DCP Midstream Business

COMBINED STATEMENTS OF CHANGES IN NET PARENT EQUITY




	Parent Equity			Accumulated Other Comprehensive Loss			Net Parent Equity
	(millions)
Balance, January 1, 2014	$	2,213		$	(2	)	$	2,211
Net income	120			—			120
Net change in parent advances	(143		)	—			(143		)
Balance, December 31, 2014	2,190			(2		)	2,188
Net loss	(1,099		)	—			(1,099		)
Net change in parent advances	3,198			—			3,198
Balance, December 31, 2015	4,289			(2		)	4,287
Net loss	(224		)	—			(224		)
Net change in parent advances	575			—			575
Balance, December 31, 2016	$	4,640		$	(2	)	$	4,638

See accompanying notes to combined financial statements.

The DCP Midstream Business

COMBINED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2016			2015			2014
	(millions)
Cash flows from operating activities:
Net (loss) income	$	(224	)	$	(1,099	)	$	120
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation and amortization	256			257			238
Amortization of debt issuance costs	12			5			5
Earnings from unconsolidated affiliates	(68		)	(11		)	(7		)
Distributions from unconsolidated affiliates	98			16			21
Deferred income tax expense (benefit)	46			(97		)	5
Net unrealized losses (gains) on derivative instruments	31			(177		)	43
Asset impairments	—			830			18
Loss (gain) on sale of assets, net	12			(42		)	7
Other, net	15			18			27
Changes in operating assets and liabilities which provided (used) cash:
Accounts receivable	(270		)	460			393
Inventories	(20		)	9			12
Accounts payable	200			(382		)	(461		)
Accrued liabilities	10			15			(30		)
Other, net	(28		)	(13		)	(86		)
Net cash provided by (used in) operating activities	70			(211		)	305
Cash flows from investing activities:
Capital expenditures	(107		)	(530		)	(1,046		)
Investments in unconsolidated affiliates, net	(24		)	(2		)	(10		)
Proceeds from sale of assets	3			164			993
Net cash used in investing activities	(128		)	(368		)	(63		)
Cash flows from financing activities:
Net parent advances	575			1,698			(301		)
Proceeds from long-term debt	1,386			5,663			—
Payment of long-term debt	(1,476		)	(5,767		)	—
(Repayment) proceeds of commercial paper, net	—			(1,012		)	47
Payment of deferred financing costs	(10		)	(4		)	(5		)
Net cash provided by (used in) financing activities	475			578			(259		)
Net change in cash and cash equivalents	417			(1		)	(17		)
Cash and cash equivalents, beginning of period	1			2			19
Cash and cash equivalents, end of period	$	418		$	1		$	2

See accompanying notes to combined financial statements.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

1. Description of Business and Basis of Presentation

The DCP Midstream Business, or the Business, we, our, or us operates in the midstream natural gas industry and is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas and producing, fractionating, transporting, storing and selling natural gas liquids, or NGLs, and recovering and selling condensate. Additionally, the Business generates revenues by trading and marketing natural gas and NGLs. The operations include 100% of the issued and outstanding equity interests in each of the following: (i) Gas Supply Resources Holdings, LLC a Delaware limited liability company, (ii) DCP Mobile Bay Processing, LLC, a Delaware limited liability company, (iii) DCP Dauphin Island, LLC, a Delaware limited liability company, (iv) DCP New Mexico Development, LLC, a Delaware limited liability company, (v) DCP NGL Services, LLC, a Delaware limited liability company, (vi) Cimarron River Pipeline, LLC, a Delaware limited liability company, (vii) DCP Raptor Pipeline, LLC, a Delaware limited liability company, (viii) DCP Midstream Marketing, LLC, a Delaware limited liability company, (ix) DCP NGL Operating, LLC, a Delaware limited liability company, and (x) DCP Hills Holding, LLC, a Delaware limited liability company and (xi) 99.8% of the issued and outstanding equity interests in DCP LP Holdings, LLC, a Delaware limited liability company. In addition, the Business includes the debt securities and credit facilities of DCP Midstream, LLC as disclosed in Footnote 11 - Financing of these combined financial statements. The interests in these legal entities were held by DCP Midstream, LLC for all periods presented.

DCP Midstream, LLC, or Midstream is a joint venture owned 50% by Phillips 66 and its affiliates (“Phillips 66”), and 50% by Spectra Energy Corp Inc. and its affiliates (“Spectra Energy”). See Footnote 19 - Subsequent Events for additional information regarding Spectra Energy. DCP Midstream, LP (the “Partnership”), formerly DCP Midstream Partners, LP, is a master limited partnership, of which Midstream acts as the general partner. On December 30, 2016, Midstream entered into a Contribution Agreement (the “Contribution Agreement”) with the Partnership and DCP Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. Pursuant to the Contribution Agreement, Midstream contributed to the Partnership: its ownership interests in all of its subsidiaries owning operating assets, and $424 million of cash (together the “Contributions”). In consideration for the Contributions, the Partnership issued 28,552,480 common units and 2,550,644 general partner units, in a private placement, to Midstream and the Partnership assumed $3,150 million of Midstream's debt. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. Subsequent to the Transaction, Midstream still directs our business operations. The Business does not currently have and is not expected to have any employees. The costs of the business operations including employee costs have been allocated to the business and reflected herein. Midstream and its affiliates’ employees are responsible for conducting our business and operating our assets.

These combined financial statements and related notes present the financial position, results of operations, cash flows and changes in net parent equity of the Business and were derived from the financial statements and accounting records of Midstream for purposes of the Transaction. These statements reflect the combined historical financial position, results of operations, cash flows and changes in net parent equity of the Business as if these operations had been combined for all periods presented. All intercompany transactions and accounts within the Business have been eliminated. The assets and liabilities in these combined financial statements have been reflected on a historical cost basis as all of the assets and liabilities presented are under the common control of Midstream. The combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP and the rules and regulations of the United States Securities and Exchange Commission. Because a direct ownership relationship did not exist among all the various assets comprising the Business, Midstream’s net investment in the Business is shown as net parent equity, in lieu of owner’s equity, in the combined financial statements. The allocation methodologies have been described within the notes to the combined financial statements where appropriate, and management considers the allocations to be reasonable. The financial information included herein may not necessarily reflect the combined financial position, results of operations, cash flows and changes in net parent equity of the Business in the future or what they would have been had the Business been a separate, stand-alone entity during the periods presented.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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 combined financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

Cash and Cash Equivalents — Cash and cash equivalents include all cash balances and 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.

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 held in storage for transportation, processing and sales commitments, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Accounting for Risk Management and Derivative 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 contract. 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 combined balance sheets as unrealized gains or unrealized losses on derivative instruments, with changes in the fair value recognized in the combined statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the combined 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 combined statements of operations category as the related hedged item
Fair Value Hedge	Hedge method (b)	Gross basis in the same combined statements of operations category as the related hedged item
Normal Purchases or Normal Sales	Accrual method (c)	Gross basis upon settlement in the corresponding combined statements of operations category based on purchase or sale
Other Non-Trading Derivatives	Mark-to-market method (a)	Net basis in trading and marketing gains and losses

(a) Mark-to-market method — An accounting method whereby the change in the fair value of the asset or liability is recognized in the combined statements of operations in trading and marketing gains and losses 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 combined balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the combined statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the changes 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 combined 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 combined balance sheets or combined 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 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 DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

The fair value of a derivative designated as a cash flow hedge is recorded in the combined 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 the combined balance sheets as accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the combined 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 combined 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 combined 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 in the combined balance sheets 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. The change in fair value of all derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the combined statements 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 internally developed 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 — 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.

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.

Goodwill and Intangible Assets — Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill in the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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 commodity prices and volumes), 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. Adverse changes in our business or the overall operating environment such as declines in gas production volumes, loss of significant customers or a decrease in commodity prices may affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment charges.

Intangible assets consist primarily of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

Investments in Unconsolidated Affiliates — We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred and if the loss is other than temporary. 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 and management considers the decline in value to be other than temporary, 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:


•	a 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 determine 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 prolonged period of lower commodity

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

prices or declines in production volumes 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 Premium, Discount and Expense — Premiums, discounts and costs 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 costs are recorded on the combined balance sheets within the carrying amount of long-term debt.

Revenue Recognition — We generate the majority of our revenues from gathering, processing, compressing, treating, transporting, storing and selling natural gas and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate, as well as trading and marketing of natural gas and NGLs. 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:

•

Percent-of-proceeds/index arrangements — Under percent-of-proceeds/index 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 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 or contractual recoveries 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-liquid arrangements, we do not keep any amounts related to the 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 to the price of NGLs and condensate.

•

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.

•

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 NGL products consists of physical purchases and sales, as well as 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016


▪	Delivery — Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.


▪	The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

▪

Collectability is reasonably assured — Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

We generally report revenues gross in the combined statements of operations, as we typically act as the principal in these transactions, take custody of 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 our NGL and residue gas derivative trading activities net in the combined 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. Included in the combined balance sheets as accounts receivable - other, as of December 31, 2016 and 2015, were imbalances totaling $6 million and $20 million, respectively. Included in the combined balance sheets as accounts payable - other, as of December 31, 2016 and 2015, were imbalances totaling $10 million and $25 million, respectively.

Purchases of natural gas, propane and NGLs — Purchases of natural gas and NGLs represent physical purchases from suppliers. We purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries.

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 or 2014. We had significant transactions with affiliates for the years ended December 31, 2016, 2015 and 2014. See Note 5, 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 — Our results of operations have historically been included in the consolidated federal income tax returns of Midstream. The income tax amounts reflected in the accompanying combined financial statements have been determined based on taxable income directly attributable to the Business, resulting in a stand-alone presentation. We believe the assumptions underlying the determination of income taxes are reasonable.

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 combined statements of operations, is included in the federal returns of Midstream.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

3. Recent 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. We intend to adopt this ASU when it is effective for public entities, which is 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 combined statements 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. We intend to adopt this ASU when it is effective for public entities, which is 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 combined financial statements.

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. We intend to adopt this ASU when it is effective for public entities, which is for interim and annual reporting periods beginning after December 15, 2016. The impact of this ASU will be evaluated upon the occurrence of future business combinations.

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 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. Dispositions

In July 2015, we entered into a purchase and sale agreement with a third party to sell a non-core 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 combined 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 combined 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 combined 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 66.67% 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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

On March 28, 2014, we contributed to Midstream (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 contribution of the Lucerne 1 and 2 plants are collectively referred to hereafter as the March 2014 Transactions. Midstream subsequently contributed the March 2014 Transactions to the Partnership. Total consideration for the March 2014 Transactions at closing were $1,220 million, less customary working capital and other adjustments. The March 2014 Transactions were accounted for as a distribution to Midstream within net parent equity. The proceeds attributable to the Business were $991 million. The difference between the proceeds received by Midstream and 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 was $178 million. The Business recorded its allocated portion of $47 million as a decrease in the combined statement of changes in net parent equity.

5. Agreements and Transactions with Related Parties and Affiliates

Derivative Transactions

The Business had previously entered into derivative transactions directly with the Partnership as a result of dropdown transactions whereby the Business was the counterparty. In March 2015, the Business novated these fixed price commodity derivatives for approximately $141 million, and the Partnership’s counterparty is now one of the financial institutions associated with the Partnership’s credit facility.

Contributions

On October 30, 2015, Midstream closed on the $3.0 billion contribution agreement, or Equity Contribution, with Phillips 66 and Spectra Energy under which Phillips 66 contributed to Midstream $1.5 billion in cash and Spectra Energy contributed to Midstream all of its interests in the Sand Hills and Southern Hills NGL pipelines, respectively, as capital contributions, which Midstream then contributed to us.

Phillips 66 and CPChem

We sell a portion of our 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 CPChem in the ordinary course of business.

Spectra Energy

We purchase natural gas and other NGL products from, and provide gathering, transportation and other services to Spectra Energy. We anticipate continuing to purchase commodities and provide services to Spectra Energy 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 and Southern Hills. 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC 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 Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.

We 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.

We also purchase a portion of our residue gas and NGLs, sell natural gas and other NGL products from, and provide gathering, transportation and other services to the Partnership.

Competition

Our related parties or affiliates, including the Partnership, Phillips 66 and Spectra Energy, are not restricted, under either the LLC Agreement or the Services Agreement, from competing with us. Our related parties or affiliates, including the Partnership, Phillips 66 and Spectra Energy, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

The following table summarizes our transactions with related parties and affiliates:



	Year Ended December 31,
	2016		2015			2014
	(millions)
DCP Midstream, LP:
Sales of natural gas and petroleum products - affiliates	$	100	$	61		$	179
Purchases of natural gas and petroleum products - affiliates	$	745	$	958		$	2,158
Transportation and other fees - affiliates	$	167	$	118		$	92
Trading and marketing gains (losses), net - affiliates	$	13	$	(33	)	$	(118	)
Phillips 66 (including CPChem):
Sales of natural gas and petroleum products - affiliates	$	909	$	695		$	1,959
Purchases of natural gas and petroleum products - affiliates	$	18	$	—		$	11
Operating and maintenance and general and administrative expenses	$	2	$	4		$	3
Spectra Energy:
Purchases of natural gas and petroleum products - affiliates	$	1	$	4		$	11
Transportation and other fees - affiliates	$	—	$	—		$	4
Operating and maintenance and general and administrative expenses	$	4	$	6		$	10
Unconsolidated affiliates:
Sales of natural gas and petroleum products - affiliates	$	43	$	70		$	70
Transportation, processing and other - affiliates	$	5	$	3		$	12
Purchases of natural gas and petroleum products - affiliates	$	432	$	368		$	362

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

We had balances with related parties and affiliates as follows:



	December 31,		December 31,
	2016		2015
	(millions)
DCP Midstream, LP:
Accounts receivable	$	28	$	15
Accounts payable	$	94	$	81
Unrealized gains on derivative instruments - current	$	22	$	18
Unrealized gains on derivative instruments - long-term	$	—	$	1
Unrealized losses on derivative instruments - current	$	15	$	32
Unrealized losses on derivative instruments - long-term	$	—	$	9
Phillips 66 (including CPChem):
Accounts receivable	$	115	$	54
Accounts payable	$	4	$	3
Other assets	$	2	$	1
Spectra Energy:
Accounts receivable	$	1	$	—
Other assets	$	1	$	1
Other liabilities	$	1	$	—
Unconsolidated affiliates:
Accounts receivable	$	18	$	21
Accounts payable	$	41	$	33
Other assets	$	5	$	31

6. Inventories

Inventories of $28 million and $8 million as of December 31, 2016 and 2015, respectively were are comprised primarily of NGLs. We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the combined statements of operations. We recognized no lower of cost or market adjustments during the years ended December 31, 2016, 2015 and 2014, respectively.

7. Property, Plant and Equipment

Property, plant and equipment by classification were as follows:



	Depreciable	December 31,			December 31,
	Life	2016			2015
		(millions)
Gathering and transmission systems	20 - 50 years	$	6,514		$	6,478
Processing, storage and terminal facilities	35 - 60 years	2,792			2,775
Other	3 - 30 years	439			421
Construction work in progress		82			74
Property, plant and equipment		9,827			9,748
Accumulated depreciation		(4,030		)	(3,796		)
Property, plant and equipment, net		$	5,797		$	5,952

Interest capitalized on construction projects was less than $1 million for the year ended December 31, 2016 and $26 million for each of the years ended December 31, 2015 and 2014.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

Depreciation expense for the years ended December 31, 2016, 2015 and 2014 was $253 million, $246 million and $226 million, respectively.

Asset Retirement Obligations

As of December 31, 2016 and 2015, we had $96 million and $91 million, respectively, of asset retirement obligations, or AROs, in other long-term liabilities in the combined balance sheets. Accretion expense is recorded within operating and maintenance expense in our combined statements of operations.

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 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 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		2015
	(millions)
Balance, beginning of period	$	91	$	90
Accretion expense	5		5
Revisions in estimated cash flows	—		(4		)
Balance, end of period	$	96	$	91

8. Investments in Unconsolidated Affiliates

We had investments in the following unconsolidated affiliates accounted for using the equity method:



	Percentage	December 31,		December 31,
	Ownership	2016		2015
		(millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	1,052	$	1,051
DCP Southern Hills Pipeline, LLC	33.33%	439		446
Other unconsolidated affiliates	Various	3		3
Total investments in unconsolidated affiliates		$	1,494	$	1,500

There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $653 million and $667 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 $141 million and $144 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

Earnings from unconsolidated affiliates amounted to the following:



	Year Ended December 31,
	2016		2015		2014
	(millions)
DCP Sand Hills Pipeline, LLC	$	48	$	7	$	3
DCP Southern Hills Pipeline, LLC	20		4		2
Other unconsolidated affiliates	—		—		2
Total earnings from unconsolidated affiliates	$	68	$	11	$	7

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



	Year Ended December 31,
	2016		2015		2014
	(millions)
Statements of operations:
Operating revenues	$	401	$	65	$	2
Operating expenses	$	142	$	22	$	1
Net income	$	258	$	43	$	1



	December 31,			December 31,
	2016			2015
	(millions)
Balance sheets:
Current assets	$	45		$	49
Long-term assets	2,286			2,265
Current liabilities	(59		)	(77		)
Long-term liabilities	(5		)	(5		)
Net assets	$	2,267		$	2,232

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

9. Goodwill and Intangible Assets

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



	December 31,
	2016			2015
	(millions)
Balance, beginning of period	$	170		$	550
Impairment	—			(378		)
Dispositions	(6		)	(2		)
Balance, end of period	$	164		$	170

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 management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the entire amount of goodwill disclosed on the combined 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 discount rate, volume forecasts, 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.

In the second quarter of 2015, we determined that continued weak commodity prices caused a change in circumstances warranting an interim impairment test. Using the fair value approaches described within the Summary of Significant Accounting Policies, we determined that the estimated fair value of certain reporting units was less than the carrying amount.

We then allocated the estimated fair value of the assets and liabilities in a hypothetical purchase price allocation and recognized goodwill impairment of $378 million in the interim impairment test.

We performed our annual goodwill assessment during the third quarter of 2015. We concluded that the fair value of the remaining goodwill exceeded the carrying value, and the entire amount of goodwill disclosed on the combined balance sheet is recoverable, therefore, no other goodwill impairments were identified or recorded as a result of the annual goodwill assessment.

Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. 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. If our forecast indicates lower commodity prices in future periods at a level and duration that results in producers curtailing or redirecting drilling in areas where we operate, it 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.

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 combined balance sheets as intangible assets, net, and are as follows:



	December 31,
	2016			2015
	(millions)
Gross carrying amount	$	246		$	246
Accumulated amortization	(90		)	(87		)
Accumulated impairment	(122		)	(122		)
Intangible assets, net	$	34		$	37

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

For the years ended December 31, 2016, 2015 and 2014, we recorded amortization expense of $3 million, $11 million and $12 million, respectively. As of December 31, 2016, the remaining amortization periods ranged from approximately 2 years to approximately 16 years, with a weighted-average remaining period of approximately 15 years.

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(millions)
2017	$	3
2018	3
2019	2
2020	2
2021	2
Thereafter	22
Total	$	34

10. 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.

•

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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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

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

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 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.

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, costless commodity collars, crude oil or NGL swaps). The exchange traded instruments are generally executed on the NYMEX exchange 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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 periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between the Contributed Entity 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 interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Benefits

We do not have our own employees. The employees and executives supporting our operations are employees of Midstream. Midstream offers certain eligible executives the opportunity to participate in the Partnership’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 combined 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 combined 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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 combined balance sheet caption and by valuation hierarchy, as of December 31, 2015:



	Net Carrying Value		Fair Value Measurements Using						Asset Impairments
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
December 31, 2015:
Goodwill	$	—	$	—	$	—	$	—	$	378
Property, plant and equipment	87		—		—		87		302
Intangible assets	36		—		—		36		122
Other assets	50		—		—		50		28
Total non-recurring assets at fair value	$	173	$	—	$	—	$	173	$	830

The following table presents the financial instruments carried at fair value on a recurring basis, by combined 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		$	49		$	9		$	63		$	22		$	65		$	14		$	101
Long-term assets:
Commodity derivatives (b)	$	—		$	—		$	5		$	5		$	3		$	14		$	3		$	20
Mutual funds (c)	—			—			—			—			8			—			—			8
Current liabilities:
Commodity derivatives (d)	$	(11	)	$	(70	)	$	(18	)	$	(99	)	$	(15	)	$	(63	)	$	(23	)	$	(101	)
Long-term liabilities:
Commodity derivatives (e)	$	(1	)	$	—		$	—		$	(1	)	$	(1	)	$	(14	)	$	(6	)	$	(21	)

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

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

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

(e) Included in long-term unrealized losses on derivative instruments in our combined 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 combined 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

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers into Level 3” and “Transfers 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 rollforwards below, the gains or losses in the tables do not reflect the effect of our total risk management activities.



	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(millions)
Year Ended December 31, 2016 (a):
Beginning balance	$	14		$	3		$	(23	)	$	(6	)
Net unrealized (losses) gains included in earnings (b)	3			2			(10		)	6
Settlements	(8		)	—			15			—
Ending balance	$	9		$	5		$	(18	)	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	9		$	3		$	(18	)	$	6

Year Ended December 31, 2015 (a):
Beginning balance	$	(115	)	$	(16	)	$	(45	)	$	(12	)
Net unrealized (losses) gains included in earnings (b)	(111		)	19			(29		)	6
Transfers out of Level 3 (c)	—			—			1			—
Settlements	121			—			50			—
Novation	119			—			—			—
Ending balance	$	14		$	3		$	(23	)	$	(6	)
Net unrealized (losses) gains on derivatives still held included in earnings (b)	$	(105	)	$	19		$	(23	)	$	4

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

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

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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.



Year Ended December 31, 2016:
Product Group	Fair Value (millions)			Forward Curve Range
Assets:
NGLs	$	14		$0.25-$1.20	Per gallon
Liabilities:
NGLs	$	(18	)	$0.25-$1.08	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.

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

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value. We determine the fair value of our variable rate debt based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We determine the fair value of our fixed-rate debt based on quotes obtained from bond dealers. We classify the fair value

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

of our outstanding debt balances within Level 2 of the fair value hierarchy. As of December 31, 2016 and 2015, the carrying value and fair value of our long-term debt were as follows:



	December 31, 2016				December 31, 2015
	Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)
Total debt	$	3,171	$	3,178	$	3,266	$	2,729

(a) Excludes unamortized issuance costs.

11. Financing

The following debt securities will be assumed by the Partnership upon consummation of the Transaction:



	December 31,			December 31,
	2016			2015
	(millions)
Debt securities:
Senior notes:
Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)	$	450		$	450
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 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
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 30, 2016, weighted average interest rate of 2.93% at December 31, 2015	—			96
Fair value adjustments related to interest rate swap fair value hedges (a)	24			26
Unamortized issuance costs	(14		)	(21		)
Unamortized discount	(3		)	(6		)
Total long-term debt	$	3,157		$	3,245

(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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2016:



Debt Maturities
(millions)
2017	$	—
2018	—
2019	450
2020	600
2021	500
Thereafter	1,600
	3,150
Fair value adjustments related to interest rate swap fair value hedges	24
Unamortized issuance costs	(14		)
Unamortized discount	(3		)
Long-term debt	$	3,157

Debt Securities

Our debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. The senior debt securities are senior unsecured obligations and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior debt. The debt securities are not guaranteed by any of our assets and are therefore, structurally subordinated to all debt and other liabilities. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time. 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 combined balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

Credit Facilities With Financial Institutions

In May 2016, we entered into a second amendment of the DCP Midstream Amended and Restated Revolving 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.

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. Certain of Midstream's subsidiaries, other than the Partnership, provided guarantees of borrowings under this facility, including legal entities of the Business. In addition, borrowings under this facility were secured with a pledge of Midstream's limited partner and general partner ownership in the Partnership as collateral. 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.

12. 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

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

commodity prices and counterparty credit. Our Risk Management Committee is composed of senior executives of Midstream 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 pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our pipeline assets through our commodity derivative program. The commercial activities related to our 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 combined 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 combined statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

Commodity Cash Flow 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 statements of operations as trading and marketing gains, net.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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 combined 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 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 through 2019, 2020 and 2030, the original maturity dates of the debt.

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, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. 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.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016


•	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.

•

In some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. For example, if we were to fail to make a required interest or principal payment on a debt instrument, above a predefined threshold level, and after giving effect to any applicable notice or grace period as defined in the ISDA contracts, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative positions.

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 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, as of December 31, 2015, all of our individual commodity derivative contracts that contained credit-risk related contingent features were in a net asset 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 have not been 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. As of December 31, 2015, we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contacts that contain credit-risk related contingent features were in a net asset position.

Collateral

As of December 31, 2016 and 2015, we had cash deposits of $62 million and $7 million, respectively included in other current assets in our combined balance sheets, and letters of credit of $13 million, for each of the two years ended December 31, 2016 and 2015, with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of December 31, 2016 and 2015, we held cash of $5 million and $10 million, respectively, included in other current liabilities in our combined balance sheet, related to cash postings by third parties and letters of credit of $38 million and $20 million, respectively 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 in our combined 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 DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

The following tables summarize the gross and net amounts of our derivative instruments:



	December 31, 2016
	Gross amounts of assets (liabilities) presented in the Balance Sheet			Gross amounts offset in the Balance Sheet		Net amounts of assets (liabilities) presented in the Balance Sheet			Amounts not offset in the Balance Sheet			Net Amount
	(millions)
Assets:
Commodity derivative instruments	$	68		$	—	$	68		$	(15	)	$	53
Liabilities:
Commodity derivative instruments	$	(100	)	$	—	$	(100	)	$	15		$	(85	)

	December 31, 2015
	Gross amounts of assets (liabilities) presented in the Balance Sheet			Gross amounts offset in the Balance Sheet		Net amounts of assets (liabilities) presented in the Balance Sheet			Amounts not offset in the Balance Sheet and Cash Collateral Received (a)			Net Amount
Assets:	(millions)
Commodity derivative instruments	$	121		$	—	$	121		$	(20	)	$	101
Liabilities:
Commodity derivative instruments	$	(122	)	$	—	$	(122	)	$	19		$	(103	)

(a) Cash collateral received of $1 million is included in other current liabilities in our combined balance sheets.

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 combined balance sheets, by major category, is summarized below:



	December 31,		December 31,			December 31,			December 31,
Balance Sheet Line Item	2016		2015		Balance Sheet Line Item	2016			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	$	63	$	101	Unrealized losses on derivative instruments – current	$	(99	)	$	(101	)
Unrealized gains on derivative instruments – long-term	5		20		Unrealized losses on derivative instruments – long-term	(1		)	(21		)
	$	68	$	121		$	(100	)	$	(122	)

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

The following table summarizes the balance and activity within AOCI relative to our interest rate derivatives, as of and for the year ended months ended December 31, 2016:



	Interest Rate Derivatives			Total
	(millions)
Net deferred gains in AOCI, beginning balance	$	(2	)	$	(2	)
Net deferred gains in AOCI, ending balance	$	(2	)	$	(2	)
Deferred gains in AOCI expected to be reclassified into earnings over the next 12 months	$	—		$	—

The following table summarizes the balance and activity within AOCI relative to our interest rate derivatives, as of and for the year ended months ended December 31, 2015:



	Interest Rate Derivatives			Total
	(millions)
Net deferred gains in AOCI, beginning balance	$	(2	)	$	(2	)
Net deferred gains in AOCI, ending balance	$	(2	)	$	(2	)

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

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



		Year Ended December 31,
Commodity Derivatives: Statement of Operations Line Item		2016			2015			2014
Third Party:	(millions)
Realized gains (losses)		$	44		$	(85	)	$	47
Unrealized (losses) gains		(60		)	152			5
Trading and marketing (losses) gains, net		$	(16	)	$	67		$	52
Affiliates:
Realized losses		$	(16	)	$	(58	)	$	(70	)
Unrealized gains (losses)		29			25			(48		)
Trading and marketing gains (losses), net - affiliates		$	13		$	(33	)	$	(118	)

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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. Additionally, relative to the hedging of certain of our storage and/or transportation assets, we may execute basis transactions for natural gas, which may result in a net long/short position of zero. These tables also present our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.



	December 31, 2016
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls) (a)		Net Short Position (MMBtu) (b)		Net (Short) Long Position (Bbls) (a)		Net Long Position (MMBtu) (b)
2017	(1,258,000	)	(23,789,350	)	(20,620,821	)	4,942,500
2018	(223,000	)	—		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) (a)		Net Short Position (MMBtu) (b)		Net (Short) Long Position (Bbls) (a)		Net (Short) Long Position (MMBtu) (b)
2016	(158,000	)	(9,178,350	)	(22,761,827	)	(457,500	)
2017	(237,000	)	—		(2,082,157	)	2,250,000
2018	—		—		120,000		—

(a) Bbls represents barrels.

(b) MMBtu represents one million British thermal units.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

13. Equity-Based Compensation

We do not have our own employees. The employees supporting our operations are employees of Midstream. Under the Midstream Long-Term Incentive plan ("Midstream LTIP"), we recorded our allocated portion of equity-based compensation expense of $18 million, $8 million, and $13 million for the years ended December 31, 2016, 2015 and 2014, respectively. The Midstream LTIP provides for the grant of Strategic Performance Units, or 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, Spectra Energy and the Partnership. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The Midstream LTIP is administered by the compensation committee of our board of directors. All awards are subject to cliff vesting.



	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2016 (millions)		Estimated Forfeiture Rate	Weighted-Average Remaining Vesting (years)
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 Midstream's 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%.

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. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our combined statements of operations.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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

14. Benefits

We do not have our own employees. The employees supporting our operations are employees of Midstream and we are allocated expenses based on those that support our combined operations. All Midstream 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, Midstream 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, Midstream 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 were allocated and expensed plan contributions of $29 million, $32 million and $30 million, respectively.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

Midstream 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. For purposes of these combined financial statements, we are accounting for our participation in these benefit plans. We recognize as expense in our combined statement of operations an allocation from Midstream for our share of payroll costs and employee benefit costs.

15. Income Taxes

We are structured as a combination of limited liability companies, which are pass-through entities for federal income tax purposes. During the year ended December 31, 2016, Midstream elected to convert the one corporation included within the entities comprising these combined financial statements, a tax paying entity which files its own federal, and state corporate income tax returns, to a limited liability company for federal income tax purposes. The income tax benefit (expense) related to this corporation was included in our income tax benefit (expense), along with state and local taxes of the limited liability entities.

Income tax (expense) benefit consisted of the following:



	Year Ended December 31,
	2016			2015		2014
	(millions)
Current:
Federal income tax expense	$	(19	)	$	—	$	—
State income tax benefit	—			—		1
Deferred:
Federal income tax (expense) benefit	(22		)	97		—
State income tax expense	(5		)	—		(6		)
Total income tax (expense) benefit	$	(46	)	$	97	$	(5	)

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	(22		)	(18		)
Total deferred income tax liabilities	(22		)	(53		)
Net deferred income tax (liability) asset	(22		)	5

Deferred income tax assets, net - noncurrent	—			23
Deferred income tax liabilities, net - noncurrent	(22		)	(18		)
Net deferred income tax (liabilities) assets	$	(22	)	$	5

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 deferred tax asset of $58 million resulting from the conversion of the corporation to a limited liability company, as discussed above.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

As of December 31, 2015, our 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 our structure as a combination of limited liability companies, which are pass-through entities for federal income tax purposes, while being treated as a taxable entities in certain states, primarily Texas.

16. Commitments and Contingent Liabilities

Litigation — The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Midstream is currently named as a defendant in some of these cases and customers have asserted individual audit claims related to mismeasurement and mispayment. Management of Midstream believes they have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These claims, however, can be costly and time consuming to defend. Midstream is also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of business, including, from time to time, disputes with customers over various measurement and settlement issues.

Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our combined results of operations, financial position or cash flows.

In January 2016, Midstream 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 was recorded in other income, net of $2 million in legal fees, in our combined statement of operations for the year December 31, 2016.

General Insurance — Our insurance coverage, managed through Midstream, 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 Midstream 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 entities with similar types of operations.

Environmental — The operation of pipelines, plants and other facilities for gathering, processing, compressing, transporting, or storing natural gas, and fractionating, transporting, gathering, processing and storing 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 and safety standards. 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 combined results of operations, financial position or cash flows.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

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.

Operating Leases — We utilize assets under operating leases in several areas of operations. Combined rental expense, including leases with no continuing commitment, amounted to $24 million, $23 million and $18 million during 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:



Minimum Rental Payments
(millions)
2017	$	44
2018	22
2019	21
2020	19
2021	16
Thereafter	29
Total minimum lease payments	$	151

17. Restructuring Costs

In April 2016, Midstream 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 the business. As a result of this headcount reduction, we recorded our allocated portion of the one-time employee termination costs of approximately $13 million, which are included in restructuring costs within total operating costs and expenses in our combined statements of operations for the year ended December 31, 2016.

As of December 31, 2016, approximately $1 million of the $13 million restructuring charges 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.

As part of Midstream's effort to create efficiencies and reduce costs, they implemented a plan to reduce general and administrative and noncore operational costs. In January 2015, they announced the initial phase of this cost reduction plan, which involved the elimination of certain corporate employee positions. As a result, we recorded our allocated portion of the 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 within total operating costs and expenses in the combined statement of operations for the year ended December 31, 2015.

The DCP Midstream Business

NOTES TO COMBINED FINANCIAL STATEMENTS — Continued

as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016

18. Supplemental Cash Flow Information



	Year Ended December 31,
	2016		2015			2014
	(millions)
Cash paid for interest, net of capitalized interest	$	222	$	207		$	201
Cash paid for income taxes, net of income tax refunds received	$	—	$	1		$	2
Contribution from member	$	—	$	1,500		$	—
Property, plant and equipment acquired with accrued liabilities	$	16	$	23		$	102
Other non-cash changes in property, plant and equipment	$	5	$	(11	)	$	23

19. Subsequent Events

We have evaluated subsequent events occurring through March 15, 2017, the date the combined financial statements were issued.

On February 27, 2017 Enbridge Inc. and Spectra Energy Corp closed their merger transaction. The combined company is known as Enbridge Inc.

Exhibit

Exhibit 99.3

DCP MIDSTREAM, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Introduction

Set forth below are DCP Midstream, LP’s unaudited pro forma condensed consolidated balance sheet as of December 31, 2016 and unaudited pro forma condensed consolidated statements of operations for each of the three years in the period ended December 31, 2016 (together with the notes to unaudited condensed consolidated financial statements, the “pro forma financial statements”). References to “we”, “our”, “us” or the “Partnership” refers to DCP Midstream, LP and its consolidated subsidiaries.

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, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Enbridge, Inc and its affiliates, or Enbridge. 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.

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.

DCP Midstream, LLC retained its respective interests in (i) DCP Midstream GP, LP (the general partner of the Partnership or “GP LP”), DCP Midstream GP, LLC (the general partner of GP LP) and the general partner interests in the Partnership, and DCP Services, LLC (the subsidiary that holds our employees)(collectively the “Excluded Subsidiaries”), and (ii) the incentive distribution rights in the Partnership, and (iii) the limited partnership interests in the Partnership (collectively, the “Excluded Interests”).

The Transaction represents a transaction between entities under common control and a change in reporting entity for the Partnership. Accordingly, the Transaction will be accounted for as an equity transaction by the Partnership and the unaudited pro forma condensed consolidated financial statements are combined on an "as if" pooled basis. The historical basis of the contributed assets and liabilities of DCP Midstream, LLC are carried forward by the Partnership.

The pro forma financial statements present the impact of the Transaction on our financial position and results of operations. The pro forma adjustments have been prepared as if the Transaction had taken place as of December 31, 2016, in the case of the unaudited pro forma condensed consolidated balance sheet, and as of January 1, 2014, in the case of the unaudited pro forma condensed consolidated statements of operations for each of the years in the three year period ended December 31, 2016.

The pro forma financial statements are qualified in their entirety by reference to historical consolidated financial statements and related notes contained therein, and should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes thereto.

DCP MIDSTREAM, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

DECEMBER 31, 2016



	DCP Midstream, LP		The DCP Midstream Business		Pro Forma Adjustments				Eliminations			DCP Midstream, LP Pro Forma
	(a)		(b)						(e)
	(Millions)
ASSETS
Current assets
Cash and cash equivalents	$	1	$	418	$	(195	)	(d)	$	—		$	224
Accounts receivable:
Trade, net	62		590		—				—			652
Affiliates	94		162		—				(122		)	134
Other	—		6		—				—			6
Inventories	44		28		—				—			72
Unrealized gains on derivative instruments	16		63		—				(37		)	42
Other	10		77		—				—			87
Total current assets	227		1,344		(195		)		(159		)	1,217
Property, plant and equipment, net	3,272		5,797		—				—			9,069
Goodwill	72		164		—				—			236
Intangible assets, net	103		34		—				—			137
Investments in unconsolidated affiliates	1,475		1,494		—				—			2,969
Unrealized gains on derivative instruments	—		5		—				—			5
Other long-term assets	12		189		—				—			201
Total assets	$	5,161	$	9,027	$	(195	)		$	(159	)	$	13,834
LIABILITIES AND EQUITY
Current liabilities:
Trade	$	108	$	569	$	—			$	—		$	677
Affiliates	31		139		—				(122		)	48
Other	—		10		—				—			10
Current maturities of long-term debt	500		—		—				—			500
Unrealized losses on derivative instruments	29		99		—				(37		)	91
Accrued interest	18		54		—				—			72
Accrued taxes	19		30		—				—			49
Accrued wages and benefits	—		72		—				—			72
Other	29		75		—				—			104
Total current liabilities	734		1,048		—				(159		)	1,623
Deferred income taxes	—		22		—				6			28
Long-term debt	1,750		3,157		(195		)	(d)	—			4,712
Unrealized losses on derivative instruments	—		1		—				—			1
Other long-term liabilities	44		161		—				(6		)	199
Total liabilities	2,528		4,389		(195		)		(159		)	6,563
Commitments and contingent liabilities
Equity:
Limited partners	2,591		—		1,125			(c)	—			3,716
	—		—		3,515			(f)	—			3,515



General partner	18			—			—				—			18
Parent equity	—			4,640			(4,640		)	(g)	—			—
Accumulated other comprehensive loss	(8		)	(2		)	—				—			(10		)
Total partners' equity	2,601			4,638			—				—			7,239
Noncontrolling interest	32			—			—				—			32
Total equity	2,633			4,638			—				—			7,271
Total liabilities and equity	$	5,161		$	9,027		$	(195	)		$	(159	)	$	13,834

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2016



	DCP Midstream, LP			The DCP Midstream Business			Pro Forma Adjustments			Eliminations			DCP Midstream, LP Pro Forma
	(a)			(b)						(e)
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	348		$	4,969		$	—		$	—		$	5,317
Sales of natural gas, propane, NGLs and condensate to affiliates	745			1,052			—			(845		)	952
Transportation, storage and processing	424			390			—			(167		)	647
Trading and marketing losses, net	(20		)	(3		)	—			—			(23		)
Total operating revenues	1,497			6,408			—			(1,012		)	6,893
Operating costs and expenses:
Purchases of natural gas, propane, NGLs and condensate	814			4,164			—			—			4,978
Purchases of natural gas, propane, NGLs and condensate from affiliates	132			1,196			—			(845		)	483
Transportation and other fees - affiliates	—			167			—			(167		)	—
Operating and maintenance	183			487			—			—			670
Depreciation and amortization	122			256			—			—			378
General and administrative	88			204			—			—			292
Other expense (income), net	7			(72		)	—			—			(65		)
(Gain) loss on sale of assets, net	(47		)	12			—			—			(35		)
Restructuring costs	—			13			—			—			13
Total operating costs and expenses	1,299			6,427			—			(1,012		)	6,714
Operating income (loss)	198			(19		)	—			—			179
Interest expense, net	(94		)	(227		)	—			—			(321		)
Earnings from unconsolidated affiliates	214			68			—			—			282
Income (loss) before income taxes	318			(178		)	—			—			140
Income tax expense	—			(46		)	—			—			(46		)
Net income (loss)	318			$	(224	)	$	—		$	—		94
Net income attributable to noncontrolling interests	(6		)										(6		)
Net income attributable to partners	312												88
General partners' interest in net income	(124		)										(164		)
Net income (loss) allocable to limited partners	$	188											$	(76	)

Net income per limited partner unit – basic and diluted	$	1.64											$	(0.53	)
Weighted-average limited partner units outstanding – basic and diluted	114.7						28.6		(c)				143.3

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2015



	DCP Midstream, LP			The DCP Midstream Business			Pro Forma Adjustments			Eliminations			DCP Midstream, LP Pro Forma
	(a)			(b)						(e)
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	484		$	5,530		$	—		$	—		$	6,014
Sales of natural gas, propane, NGLs and condensate to affiliates	958			826			—			(1,019		)	765
Transportation, storage and processing	371			279			—			(118		)	532
Trading and marketing losses, net	85			34			—			—			119
Total operating revenues	1,898			6,669			—			(1,137		)	7,430
Operating costs and expenses:
Purchases of natural gas, propane, NGLs and condensate	1,139			4,424			—			—			5,563
Purchases of natural gas, propane, NGLs and condensate from affiliates	107			1,330			—			(1,019		)	418
Transportation and other fees - affiliates	—			118			—			(118		)	—
Operating and maintenance	214			518			—			—			732
Depreciation and amortization	120			257			—			—			377
Asset impairments	82			830									912
General and administrative	85			196			—			—			281
Gain on sale of assets, net	—			(42		)	—			—			(42		)
Restructuring costs	—			11			—			—			11
Other expense, net	4			6			—			—			10
Total operating costs and expenses	1,751			7,648			—			(1,137		)	8,262
Operating income (loss)	147			(979		)	—			—			(832		)
Interest expense, net	(92		)	(228		)	—			—			(320		)
Earnings from unconsolidated affiliates	173			11			—			—			184
Income (loss) before income taxes	228			(1,196		)	—			—			(968		)
Income tax benefit	5			97			—			—			102
Net income (loss)	233			$	(1,099	)	$	—		$	—		(866		)
Net income attributable to noncontrolling interests	(5		)										(5		)
Net income attributable to partners	228												(871		)
General partners' interest in net income	(124		)										(144		)
Net income allocable to limited partners	$	104											$	(1,015	)

Net income per limited partner unit – basic and diluted	$	0.91											$	(7.09	)
Weighted-average limited partner units outstanding – basic and diluted	114.6						28.6		(c)				143.2

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2014



	DCP Midstream, LP			The DCP Midstream Business			Pro Forma Adjustments				Eliminations			DCP Midstream, LP Pro Forma
	(a)			(b)							(e)
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	963		$	10,427		$	—			$	—		$	11,390
Sales of natural gas, propane, NGLs and condensate to affiliates	2,180			2,208			(21		)	(h)	(2,337		)	2,030
Transportation, storage and processing	345			264			(1		)	(h)	(91		)	517
Trading and marketing losses, net	154			(66		)	—				—			88
Total operating revenues	3,642			12,833			(22		)		(2,428		)	14,025
Operating costs and expenses:
Purchases of natural gas, propane, NGLs and condensate	2,524			8,838			—				—			11,362
Purchases of natural gas, propane, NGLs and condensate from affiliates	271			2,542			(16		)	(h)	(2,336		)	461
Transportation and other fees - affiliates	—			96			—				(92		)	4
Operating and maintenance	216			558			—				—			774
Depreciation and amortization	110			238			—				—			348
Asset impairments	—			18			—				—			18
General and administrative	64			213			—				—			277
Other expense, net	3			4			—				—			7
Loss on sale of assets, net	—			7			—				—			7
Total operating costs and expenses	3,188			12,514			(16		)		(2,428		)	13,258
Operating income	454			319			(6		)		—			767
Interest expense, net	(86		)	(201		)	—				—			(287		)
Earnings from unconsolidated affiliates	75			7			—				—			82
Income before income taxes	443			125			(6		)		—			562
Income tax expense	(6		)	(5		)	—				—			(11		)
Net income	437			$	120		$	(6	)		$	—		551
Net income attributable to noncontrolling interests	(14		)											(14		)
Net income attributable to partners	423													537
Net income attributable to predecessor operations	(6		)											—
General partners' interest in net income	(114		)											(157		)
Net income allocable to limited partners	$	303												$	380

Net income per limited partner unit – basic and diluted	$	2.84												$	2.81
Weighted-average limited partner units outstanding – basic and diluted	106.6						28.6			(c)				135.2

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM, LP

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation

The unaudited pro forma condensed consolidated financial statements (“the pro forma financial statements”) present the impact on our financial position and results of operations of the Transaction as discussed in the Introduction to these pro forma financial statements. The pro forma financial statements as of December 31, 2016 for each of the three years in the period ended December 31, 2016 have been prepared based on certain pro forma adjustments to our audited consolidated financial statements set forth in our Annual Report on Form 10-K filed on February 15, 2017 with the Securities and Exchange Commission, and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained in that report. The pro forma financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes thereto.

The unaudited pro forma condensed consolidated balance sheet as of December 31, 2016 has been prepared as if the Transaction occurred on that date. The unaudited pro forma condensed consolidated statements of operations for each of the three years in the period ended December 31, 2016 have been prepared as if the Transaction had occurred on January 1, 2014. Since the Transaction represents a transaction between entities under common control and a change in reporting entity, the unaudited pro forma condensed consolidated financial statements are combined on an “as if” pooling basis and the historical basis of the contributed assets and liabilities are carried forward by the Partnership.

The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual results may differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the Transaction and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial statements.

Note 2. Pro Forma Adjustments and Assumptions


(a)	Amounts were derived from the audited consolidated financial statements included in our Form 10-K, as filed with the Securities and Exchange Commission (“SEC”) on February 15, 2017.


(b)	Amounts were derived from the Audited Combined Financial Statements of The DCP Midstream Business as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016, included in this Current Report on Form 8-K/A as Exhibit 99.2.


(c)	Reflects the issuance of 28,552,480 common units and 2,550,644 general partner units to DCP Midstream, LLC having an aggregate value of $1,125 million as determined by the volume weighted average price of the common units over the 20-day trading period ended December 28, 2016.


(d)	Reflects repayment of debt outstanding on the Partnership’s revolving credit facility from proceeds received in the Transaction.


(e)	To remove impacts of intercompany transactions and maintain presentational consistency of deferred income tax liabilities and other long-term liabilities.


(f)	Reflects the adjustment to limited partners’ equity for the deficit of consideration paid compared to the historical cost of the net assets acquired. The consideration was assigned as follows, subject to additional customary post-closing adjustments (in millions):



Aggregate consideration	$	4,275
Less: Historical cost of the assets acquired (excluding debt)	(7,790		)
Adjustment to limited partners’ equity for deficit consideration	$	3,515

(g) To reclassify net parent equity to limited partners equity.


(h)	To eliminate the impact of activity attributable to predecessor results included in the accounts of both DCP Midstream, LP and The DCP Midstream Business, related to the effect of pooling historical results within the DCP Midstream, LP financial statements from the March 2014 transactions (as discussed in the combined financial statements of The DCP Midstream Business).

Note 3. Pro Forma Net Income or Loss Per Limited Partner Unit

Our net income or net 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 certain distribution levels, it will have the impact of reducing net income per limited partner unit, or LPU.

Basic and diluted net income or loss per LPU is calculated by dividing limited partners’ interest in pro forma net income or loss, by the weighted average number of outstanding LPUs during the period, assuming the 28,552,480 limited partner units issued in connection with the Transaction were issued on January 1, 2014.