10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2020

or 

¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission File Number: 001-32678 

DCP MIDSTREAM, LP

(Exact name of registrant as specified in its charter) 

Delaware	03-0567133
(State or other jurisdiction of incorporation or organization)	(I.R.S. 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)

None

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common units representing limited partnership interests	DCP	New York Stock Exchange
7.875% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	DCP PRB	New York Stock Exchange
7.95% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	DCP PRC	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	ý	Accelerated filer	¨	Emerging growth company	¨
Non-accelerated filer	¨	Smaller reporting company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a)

of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨    No  ý

As of May 1, 2020, there were 208,329,928 common units representing limited partnership interests outstanding.

1

DCP MIDSTREAM, LP

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2020

TABLE OF CONTENTS

Item		Page
	PART I. FINANCIAL INFORMATION
1	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019	2
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2020 and 2019	3
	Condensed Consolidated Statements of Comprehensive (Loss) Income for the Three Months Ended March 31, 2020 and 2019	4
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019	5
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2020	6
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2019	6
	Notes to the Condensed Consolidated Financial Statements	8
2	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
3	Quantitative and Qualitative Disclosures about Market Risk	50
4	Controls and Procedures	52
	PART II. OTHER INFORMATION
1	Legal Proceedings	53
1A.	Risk Factors	53
6	Exhibits	55
	Signatures	56

i

GLOSSARY OF TERMS

The following is a list of terms used in the industry and throughout this report:

ASU	accounting standards update
Bbl	barrel
Bbls/d	barrels per day
Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Btu	British thermal unit, a measurement of energy
Credit Agreement	$1.4 billion unsecured revolving Credit Agreement, maturing December 9, 2024
Fractionation	the process by which natural gas liquids are separated     into individual components
GAAP	generally accepted accounting principles in the United States of America
IDR	incentive distribution right
MBbls	thousand barrels
MBbls/d	thousand barrels per day
MMBtu	million Btus
MMBtu/d	million Btus per day
MMcf	million cubic feet
MMcf/d	million cubic feet per day
NGLs	natural gas liquids
OPEC	Organization of the Petroleum Exporting Countries
OPEC+	OPEC members plus ten other oil producing countries
Railroad Commission	the Railroad Commission of Texas
SEC	U.S. Securities and Exchange Commission
Securitization Facility	$350 million Accounts Receivable Securitization Facility, maturing August 12, 2022
TBtu/d	trillion Btus per day
Throughput	the volume of product transported or passing through a     pipeline or other facility

ii

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “should,” “intend,” “assume,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and in our Annual Report on Form 10-K for the year ended December 31, 2019, including the following risks and uncertainties:

•the impact from the COVID-19 pandemic and disruption to economies around the world including the oil, gas and NGL industry in which we operate and the resulting adverse impact on our business, liquidity, commodity prices, workforce, third-party and counterparty effects and resulting federal, state and local actions;

•the extent of changes in commodity prices and the demand for our products and services, our ability to effectively limit a portion of the adverse impact of potential changes in commodity prices through derivative financial instruments, and the potential impact of price, and of producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

•the demand for crude oil, residue gas and NGL products;

•the level and success of drilling and quality of production volumes around our assets and our ability to connect supplies to our gathering and processing systems, as well as our residue gas and NGL infrastructure;

•new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety, regulatory and protection of the environment, including, but not limited to, climate change legislation, regulation of over-the-counter derivatives markets and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, including additional local control over such activities, and their impact on producers and customers served by our systems;

•volatility in the price of our common units and preferred units;

•general economic, market and business conditions;

•the amount of natural gas we gather, compress, treat, process, transport, store and sell, or the NGLs we produce, fractionate, transport, store and sell, may be reduced if the pipelines, storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or will not, accept the natural gas or NGLs or we may be required to find alternative markets and arrangements for our natural gas and NGLs;

•our ability to continue the safe and reliable operation of our assets;

•our ability to grow through organic growth projects, or acquisitions, and the successful integration and future performance of such assets;

•our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results, inflation rates, interest rates, our ability to comply with the covenants in our $1.4 billion unsecured revolving credit facility or other credit facilities, and the indentures governing our notes, as well as our ability to maintain our credit ratings;

•the creditworthiness of our customers and the counterparties to our transactions;

•the amount of collateral we may be required to post from time to time in our transactions;

•industry changes, including the impact of bankruptcies, consolidations, alternative energy sources, technological advances, infrastructure constraints and changes in competition;

•our ability to construct and start up facilities on budget and in a timely fashion, which is partially dependent on obtaining required construction, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for materials;

•our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;

•weather, weather-related conditions and other natural phenomena, including, but not limited to, their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;

•security threats such as terrorist attacks, and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems; and

•our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our losses.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. The forward-looking statements in this report speak as of the filing date of this report. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws.

iii

PART I

Item 1. Financial Statements

1

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	March 31, 2020		December 31, 2019
ASSETS	(millions)
Current assets:
Cash and cash equivalents	$	18	$	1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $2 and $3 million, respectively	485		726
Affiliates	98		138
Other	14		14
Inventories	26		46
Unrealized gains on derivative instruments	252		32
Collateral cash deposits	35		111
Other	30		12
Total current assets	958		1,080
Property, plant and equipment, net	8,180		8,811
Goodwill	—		159
Intangible assets, net	48		61
Investments in unconsolidated affiliates	3,681		3,724
Unrealized gains on derivative instruments	53		2
Operating lease assets	98		107
Other long-term assets	170		183
Total assets	$	13,188	$	14,127
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	329	$	638
Affiliates	97		100
Other	26		35
Current debt	3		603
Unrealized losses on derivative instruments	192		58
Accrued interest	67		80
Accrued taxes	69		65
Accrued wages and benefits	25		58
Capital spending accrual	10		28
Other	148		128
Total current liabilities	966		1,793
Long-term debt	5,921		5,321
Unrealized losses on derivative instruments	46		20
Deferred income taxes	30		30
Operating lease liabilities	83		88
Other long-term liabilities	226		242
Total liabilities	7,272		7,494
Commitments and contingent liabilities (see note 17)
Equity:
Series A preferred limited partners (500,000 preferred units authorized, issued and outstanding, respectively)	498		489
Series B preferred limited partners (6,450,000 preferred units authorized, issued and outstanding, respectively)	156		156
Series C preferred limited partners (4,400,000 preferred units authorized, issued and outstanding, respectively)	106		106
Limited partners (208,329,928 common units authorized, issued and outstanding, respectively)	5,135		5,861
Accumulated other comprehensive loss	(7)		(7)
Total partners’ equity	5,888		6,605
Noncontrolling interests	28		28
Total equity	5,916		6,633
Total liabilities and equity	$	13,188	$	14,127

See accompanying notes to condensed consolidated financial statements.

2

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2020		2019
	(millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	1,171	$	1,771
Sales of natural gas, NGLs and condensate to affiliates	222		340
Transportation, processing and other	112		115
Trading and marketing gains (losses), net	152		(27)
Total operating revenues	1,657		2,199
Operating costs and expenses:
Purchases and related costs	872		1,533
Purchases and related costs from affiliates	36		62
Transportation and related costs from affiliates	238		209
Operating and maintenance expense	153		178
Depreciation and amortization expense	99		103
General and administrative expense	56		67
Asset impairments	746		—
Other expense, net	3		5
Loss on sale of assets, net	—		9
Total operating costs and expenses	2,203		2,166
Operating (loss) income	(546)		33
Earnings from unconsolidated affiliates	76		113
Interest expense, net	(78)		(69)
(Loss) income before income taxes	(548)		77
Income tax expense	(1)		(1)
Net (loss) income	(549)		76
Net income attributable to noncontrolling interests	(1)		(1)
Net (loss) income attributable to partners	(550)		75
Series A preferred limited partners' interest in net (loss) income	(9)		(9)
Series B preferred limited partners' interest in net (loss) income	(3)		(3)
Series C preferred limited partners' interest in net (loss) income	(2)		(2)
General partner’s interest in net income	—		(41)
Net (loss) income allocable to limited partners	$	(564)	$	20
Net (loss) income per limited partner unit — basic and diluted	$	(2.71)	$	0.14
Weighted-average limited partner units outstanding — basic and diluted	208.3		143.3

See accompanying notes to condensed consolidated financial statements.

3

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(unaudited)

	Three Months Ended March 31,
	2020		2019
	(millions)
Net (loss) income	$	(549)	$	76
Other comprehensive income:
Total other comprehensive income	—		—
Total comprehensive (loss) income	(549)		76
Total comprehensive income attributable to noncontrolling interests	(1)		(1)
Total comprehensive (loss) income attributable to partners	$	(550)	$	75

See accompanying notes to condensed consolidated financial statements.

4

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2020		2019
	(millions)
OPERATING ACTIVITIES:
Net (loss) income	$	(549)	$	76
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization expense	99		103
Earnings from unconsolidated affiliates	(76)		(113)
Distributions from unconsolidated affiliates	153		124
Net unrealized (gains) losses on derivative instruments	(134)		54
Loss on sale of assets, net	—		9
Asset impairments	746		—
Other, net	17		6
Change in operating assets and liabilities, which provided (used) cash:
Accounts receivable	282		118
Inventories	16		14
Accounts payable	(310)		29
Other assets and liabilities	70		(103)
Net cash provided by operating activities	314		317
INVESTING ACTIVITIES:
Capital expenditures	(69)		(182)
Investments in unconsolidated affiliates	(34)		(131)
Proceeds from sale of assets	—		103
Net cash used in investing activities	(103)		(210)
FINANCING ACTIVITIES:
Proceeds from debt	2,151		1,402
Payments of debt	(2,152)		(1,348)
Distributions to preferred limited partners	(5)		(5)
Distributions to limited partners and general partner	(162)		(154)
Distributions to noncontrolling interests	(1)		(1)
Other	(2)		(1)
Net cash used in financing activities	(171)		(107)
Net change in cash, cash equivalents and restricted cash	40		—
Cash, cash equivalents and restricted cash, beginning of period	1		1
Cash, cash equivalents and restricted cash, end of period	$	41	$	1
Reconciliation of cash, cash equivalents, and restricted cash:	March 31, 2020		March 31, 2019
Cash and cash equivalents	$	18	$	1
Restricted cash included in other current assets	12		—
Restricted cash included in other long-term assets	11		—
Total cash, cash equivalents, and restricted cash	$	41	$	1

See accompanying notes to condensed consolidated financial statements.

5

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)

	Partners’ Equity
		Series A Preferred Limited Partners		Series B Preferred Limited Partners		Series C Preferred Limited Partners		Limited  Partners		Accumulated  Other Comprehensive Loss		Noncontrolling Interests		Total Equity
	(millions)
Balance, January 1, 2020		$	489	$	156	$	106	$	5,861	$	(7)	$	28	$	6,633
Net income (loss)		9		3		2		(564)		—		1		(549)
Distributions to unitholders		—		(3)		(2)		(162)		—		—		(167)
Distributions to noncontrolling interests		—		—		—		—		—		(1)		(1)
Balance, March 31, 2020		$	498	$	156	$	106	$	5,135	$	(7)	$	28	$	5,916

See accompanying notes to condensed consolidated financial statements.

6

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)

	Partners’ Equity
		Series A Preferred Limited Partners		Series B Preferred Limited Partners		Series C Preferred Limited Partners		Limited  Partners		General  Partner		Accumulated  Other Comprehensive Loss		Noncontrolling Interests		Total Equity
	(millions)
Balance, January 1, 2019		$	489	$	156	$	106	$	6,418	$	107	$	(8)	$	29	$	7,297
Net income		9		3		2		20		41		—		1		76
Distributions to unitholders		—		(3)		(2)		(111)		(43)		—		—		(159)
Distributions to noncontrolling interests		—		—		—		—		—		—		(1)		(1)
Balance, March 31, 2019		$	498	$	156	$	106	$	6,327	$	105	$	(8)	$	29	$	7,213

See accompanying notes to condensed consolidated financial statements.

7

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019

(Unaudited)

1. Description of Business and Basis of Presentation

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

Our Partnership includes our Logistics and Marketing and Gathering and Processing segments. For additional information regarding these segments, see Note 18 - Business Segments.

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and which is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Enbridge Inc. and its affiliates, or Enbridge. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of March 31, 2020, DCP Midstream, LLC, together with our general partner, owned approximately 57% of us through limited partner interests.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

The condensed consolidated financial statements have been prepared in accordance with GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could differ from these estimates, which may be significantly impacted by various factors, including those outside of our control, such as the impact of a sustained deterioration in commodity prices and volumes, which would negatively impact our results of operations, financial condition and cash flows. All intercompany balances and transactions have been eliminated in consolidation.

These unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three months ended March 31, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2019 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019.

2. Update to Significant Accounting Policies

Cash, Cash Equivalents, and Restricted Cash - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents. Restricted cash primarily consists of amounts held in our non-qualified deferred compensation plan. Restricted cash is excluded from cash and cash equivalents and is included in other current or non-current assets.

3. Recent Accounting Pronouncements

FASB ASU, 2020-04 “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” or ASU 2020-04 - In March 2020, the FASB issued ASU 2020-04, which provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This ASU is effective for interim and annual reporting periods that include or are subsequent to March 12, 2020. We adopted this ASU on March 12, 2020 and it did not have a material impact on our condensed consolidated financial statements.

8

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

FASB ASU, 2018-15 “Intangibles - Goodwill and Other - Internal-use Software (Subtopic 350-40): Customers Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract” or ASU 2018-15 - In August 2018, the FASB issued ASU 2018-15, which aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service contract with the guidance on capitalizing costs associated with developing or obtaining internal-use software. This ASU is effective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have not been issued. We adopted this ASU on January 1, 2020 and it did not have a material impact on our condensed consolidated financial statements.

FASB ASU, 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” or ASU 2016-13 - In June 2016, the FASB issued ASU 2016-13, which amends current measurement techniques used to estimate credit losses for financial assets. This ASU is effective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have not been issued. We adopted this ASU on January 1, 2020 and it did not have a material impact on our condensed consolidated financial statements.

4. Revenue Recognition

We disaggregate our revenue from contracts with customers by type of contract for each of our reportable segments, as we believe it best depicts the nature, timing and uncertainty of our revenue and cash flows. The following tables set forth our revenue by those categories:

	Three Months Ended March 31, 2020
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	411	$	326	$	(290)	$	447
Sales of NGLs and condensate (a)	883		387		(324)		946
Transportation, processing and other	13		99		—		112
Trading and marketing gains, net (b)	51		101		—		152
Total operating revenues	$	1,358	$	913	$	(614)	$	1,657

	Three Months Ended March 31, 2019
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	637	$	557	$	(498)	$	696
Sales of NGLs and condensate (a)	1,403		648		(636)		1,415
Transportation, processing and other	12		103		—		115
Trading and marketing losses, net (b)	(7)		(20)		—		(27)
Total operating revenues	$	2,045	$	1,288	$	(1,134)	$	2,199

(a)   Includes $591 million and $858 million for the three months ended March 31, 2020 and 2019, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment, which are not within the scope of Topic 606.

(b)   Not within the scope of Topic 606.

The revenue expected to be recognized in the future related to performance obligations that are not satisfied is approximately $383 million as of March 31, 2020. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to be recognized through 2028 with a weighted average remaining life of four years as of March 31, 2020. As a practical expedient permitted by Topic 606, this amount excludes variable consideration as well as remaining performance obligations that have original expected durations of one year or less, as applicable. Our remaining performance obligations also exclude estimates of variable rate escalation clauses in our contracts with customers.

5. Contract Liabilities

Our contract liabilities consist of deferred revenue received from reimbursable projects. The noncurrent portion of deferred revenue is included in other long-term liabilities on our condensed consolidated balance sheets.

9

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

The following table summarizes changes in contract liabilities included in our condensed consolidated balance sheets:

	March 31,
	2020
	(millions)
Balance, beginning of period	$	33
Additions	2
Revenue recognized (a)	(1)
Balance, end of period	$	34

(a) Deferred revenue recognized is included in transportation, processing and other on the condensed consolidated statement of operations.

The contract liabilities disclosed in the table above will be recognized as revenue as the obligations are satisfied over their average remaining contract life, which is 35 years as of March 31, 2020.

6. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

Under the Services and Employee Secondment Agreement (the “Services Agreement”), we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. The following table summarizes employee related costs that were charged by DCP Midstream, LLC to the Partnership that are included in the condensed consolidated statements of operations:

		Three Months Ended March 31,
		2020		2019
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense		$	44	$	49
General and administrative expense		$	35	$	47

Phillips 66 and its Affiliates

We sell a portion of our residue gas and NGLs to and purchase NGLs from Phillips 66 and its respective affiliates. We anticipate continuing to sell commodities to and purchase commodities from Phillips 66 and its affiliates in the ordinary course of business.

Unconsolidated Affiliates

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

10

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Three Months Ended March 31,
	2020		2019
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	212	$	326
Purchases and related costs from affiliates	$	27	$	31
Transportation and related costs from affiliates	$	23	$	14
Operating and maintenance and general administrative expenses	$	4	$	4
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	1	$	—
Purchases and related costs from affiliates	$	—	$	7
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	9	$	14
Transportation, processing, and other to affiliates	$	3	$	1
Purchases and related costs from affiliates	$	9	$	24
Transportation and related costs from affiliates	$	215	$	195

 We had balances with affiliates as follows:

	March 31, 2020		December 31, 2019
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	81	$	117
Accounts payable	$	27	$	20
Enbridge (including its affiliates):
Accounts payable	$	—	$	2
Unconsolidated affiliates:
Accounts receivable	$	17	$	21
Accounts payable	$	70	$	78

7. Inventories

Inventories were as follows: 

	March 31, 2020		December 31, 2019
	(millions)
Natural gas	$	17	$	19
NGLs	9		27
Total inventories	$	26	$	46

We recognize lower of cost or net realizable value adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases and related costs in the condensed consolidated statements of operations. We recognized $4 million and $5 million of lower of cost or net realizable value adjustments during the three months ended March 31, 2020 and 2019, respectively.

11

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

8. Property, Plant and Equipment

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

	Depreciable Life	March 31, 2020		December 31, 2019
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,677	$	8,406
Processing, storage and terminal facilities	35 — 60 Years	4,873		5,305
Other	3 — 30 Years	577		585
Finance lease assets	4 — 7 Years	21		25
Construction work in progress		194		183
Property, plant and equipment		13,342		14,504
Accumulated depreciation		(5,162)		(5,693)
Property, plant and equipment, net		$	8,180	$	8,811

Interest capitalized on construction projects was $2 million and $5 million for the three months ended March 31, 2020 and 2019, respectively.

Depreciation expense was $97 million and $101 million for the three months ended March 31, 2020 and 2019, respectively.

9. Goodwill

We perform our annual goodwill assessment during the third quarter at the reporting unit level, and update the test during interim periods when we believe events or changes in circumstances indicate that it is more likely than not that an impairment exists. During the first quarter of 2020, certain areas of our business, as well as those of other midstream companies in our peer group, suffered a significant decline in market value. This indicated both a reduction of estimated enterprise value and an increase to our estimated discount rate. Our goodwill impairment assessment is conducted by assessing whether (i) the components of our operating segments constitute businesses for which discrete financial information is available, (ii) segment management regularly reviews the operating results of those components and (iii) the economic and regulatory characteristics are similar. As a result of the increase in our estimated discount rate coupled with a decline in forecasted cash flows due to commodity pricing, we concluded the carrying value of goodwill in the North reporting unit within our Gathering and Processing segment was more likely than not impaired. Therefore, we performed an analysis to determine the estimated fair value of the North reporting unit as of March 31, 2020 and concluded that its carrying value exceeded its fair value by more than the recorded amount of goodwill within the reporting unit, resulting in an impairment charge of $159 million.

The significant decline in commodity prices and demand have decreased forecasted cash flows such that, while in excess of asset book value on an undiscounted basis, they were not sufficient to recover the value of allocated goodwill in the North reporting unit.

We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform our goodwill assessment. Key assumptions in the analysis include the use of an appropriate discount rate, a terminal year multiple, 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. To estimate the discount rate, we used a capital asset pricing model to calculate a rate believed to be consistent with those utilized by market participants.

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

12

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

	As of March 31, 2020						As of March 31, 2019
	Gathering and Processing		Logistics and Marketing		Total		Gathering and Processing		Logistics and Marketing		Total
	(millions)
Balance, beginning of period	$	159	$	—	$	159	$	159	$	72	$	231
Impairment	(159)		—		(159)		—		—		—
Dispositions	—		—		—		—		(37)		(37)
Balance, end of period	$	—	$	—	$	—	$	159	$	35	$	194

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

	March 31,		December 31,
	2020		2019
	(millions)
Gross carrying amount	$	145	$	145
Accumulated amortization	(86)		(84)
Accumulated impairment	(11)		—
Intangible assets, net	$	48	$	61

10. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	March 31, 2020		December 31, 2019
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,768	$	1,764
DCP Southern Hills Pipeline, LLC	66.67%	742		738
Front Range Pipeline LLC	33.33%	209		206
Gulf Coast Express LLC	25.00%	445		449
Texas Express Pipeline LLC	10.00%	100		101
Cheyenne Connector	50.00%	100		83
Mont Belvieu Enterprise Fractionator	12.50%	27		27
Mont Belvieu 1 Fractionator	20.00%	8		9
Discovery Producer Services LLC	40.00%	256		322
Panola Pipeline Company, LLC	15.00%	22		22
Other	Various	4		3
Total investments in unconsolidated affiliates		$	3,681	$	3,724

13

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

Earnings from investments in unconsolidated affiliates were as follows:

	Three Months Ended March 31,
	2020		2019
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	68
DCP Southern Hills Pipeline, LLC	20		23
Front Range Pipeline LLC	11		7
Gulf Coast Express LLC	16		—
Texas Express Pipeline LLC	4		5
Mont Belvieu Enterprise Fractionator	3		4
Mont Belvieu 1 Fractionator	3		4
Discovery Producer Services LLC (a)	(61)		—
Other	2		2
Total earnings from unconsolidated affiliates	$	76	$	113

(a)See Note 11 for further discussion

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

	Three Months Ended March 31,
	2020		2019
	(millions)
Statements of operations:
Operating revenue	$	527	$	421
Operating expenses	$	185	$	191
Net income	$	341	$	231

	March 31, 2020		December 31, 2019
	(millions)
Balance sheets:
Current assets	$	368	$	463
Long-term assets	7,598		7,546
Current liabilities	(169)		(231)
Long-term liabilities	(257)		(252)
Net assets	$	7,540	$	7,526

11. Fair Value Measurement

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.

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DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

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

Commodity Derivative Assets and Liabilities

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

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

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming online, 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.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, equity investments in unconsolidated affiliates, and intangible assets. 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 condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

During the three months ended March 31, 2020, it was determined that triggering events had occurred with respect to specific asset groups as a result of the impact of commodity prices on the respective recently prepared budget forecasts, coupled with a negative outlook for long-term production volume forecasts for these asset groups. As a result, we recognized a

15

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

$587 million impairment loss associated with certain asset groups in the Permian and South regions of our Gathering and Processing segment and an impairment of $61 million of our equity investment in Discovery Producer Services LLC (“Discovery”).

The $461 million impairment of certain gathering and processing assets in the Permian region was driven by the impact of the decrease of gas, NGL and condensate prices at March 31, 2020 on our forecasts for the assets. This assessment triggered an impairment analysis, and based on forecasted future undiscounted cash flows, management determined the carrying value of these asset groups were not fully recoverable. We used the income approach to calculate the fair value of the asset groups and compared it to the carrying value. The primary inputs were the forecasted future commodity pricing and the discount rate. The impairment amount recorded represented the difference between the fair and carrying values.

The $126 million impairment of certain gathering and processing assets in the South region was driven by a negative outlook for long-term gathering and processing volumes at more price sensitive assets as a result of decreased production forecasts. This revised outlook triggered an impairment analysis, and based on forecasted future undiscounted cash flows, management determined that the carrying value of these asset groups were not fully recoverable. We used the income approach to calculate the fair value of the asset group and compared it to the carrying value. The primary inputs to our calculation were forecasted future commodity pricing and the discount rate. The impairment amount recorded represented the difference between the fair and carrying values.

The $61 million impairment of Discovery was driven by market conditions that existed at March 31, 2020, which given the nature of the overall commodity price environment, the diminished probability of new well connects and projected volume decline, resulted in our determination that the decline in fair value was other than temporary. The estimate of fair value, which was based on an income approach, included assumptions such as future commodity prices from a combination of market pricing, investment bank research, ratings agencies, and industry outlooks, future cash flows based on our price and volume assumptions, terminal year multiple and discount rate. The impairment loss is included in earnings from unconsolidated affiliates in our condensed consolidated statement of operations.

We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets and investments that could result in future impairments. Such impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.

The following table presents the carrying value of certain assets and asset groups measured at fair value on a non-recurring basis, by condensed consolidated balance sheet caption as of and for the three months ended March 31, 2020.

	Fair Value Measurements Using Inputs Considered as
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
Long-lived assets	$	96	$	—	$	—	$	96	$	587
Goodwill	—		—		—		—		159
Direct investment in unconsolidated affiliate	256		—		—		256		61
Total impairments	$	352	$	—	$	—	$	352	$	807

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DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

The following table summarizes the significant unobservable inputs used in the valuation of certain assets and asset groups measured at fair value on a non-recurring basis as of March 31, 2020.

	March 31, 2020
Asset Groups	Valuation Techniques	Unobservable Inputs	Range (low-high) (a)	Average (b)
Long-lived assets, investment in unconsolidated affiliate, goodwill	Discounted cash flow	Oil prices	$34.52 - $67.61	$	55.98	Per barrel
		Natural gas prices	$2.28 - $4.12	$	3.35	Per MMBtu
		NGL prices	$0.30 - $0.62	$	0.52	Per gallon
		Discount rate	14%	14%
		Terminal value multiple	8x	8x
Goodwill	Market comparable companies	EBITDA multiple	5.2x - 16.5x	8x

(a)Commodity prices represent an average per year

(b)Represents the arithmetic average of the inputs and is not weighted by the relative fair value or volumetric amount.

The following table presents the financial instruments carried at fair value on a recurring basis as of March 31, 2020 and December 31, 2019, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:

	March 31, 2020								December 31, 2019
	Level 1		Level 2		Level 3		Total Carrying Value		Level 1		Level 2		Level 3		Total Carrying Value
	(millions)
Current assets:
Commodity derivatives	$	233	$	11	$	8	$	252	$	13	$	15	$	4	$	32
Long-term assets:
Commodity derivatives	$	47	$	5	$	1	$	53	$	1	$	1	$	—	$	2
Current liabilities:
Commodity derivatives	$	(169)	$	(20)	$	(3)	$	(192)	$	(15)	$	(42)	$	(1)	$	(58)
Long-term liabilities:
Commodity derivatives	$	(34)	$	(11)	$	(1)	$	(46)	$	(2)	$	(15)	$	(3)	$	(20)

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.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently

17

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.

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

	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended March 31, 2020 (a):
Beginning balance	$	4	$	—	$	(1)	$	(3)
Net unrealized gains included in earnings	8		1		5		2
Settlements	(4)		—		(7)		—
Ending balance	$	8	$	1	$	(3)	$	(1)
Three months ended March 31, 2019 (a):
Beginning balance	$	14	$	2	$	—	$	(2)
Net unrealized (losses) gains included in earnings	(4)		(1)		(2)		1
Transfers out of Level 3	(2)		—		—		—
Settlements	(3)		—		1		—
Ending balance	$	5	$	1	$	(1)	$	(1)

(a)There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three months ended March 31, 2020 and 2019.

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

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

	March 31, 2020
Product Group	Fair Value		Valuation Techniques	Unobservable Input	Forward Curve Range	Weighted Average (a)
	(millions)
Assets
NGLs	$	9	Market approach	Longer dated forward curve prices	$0.11-$0.47	$0.33	Per gallon
Liabilities
NGLs	$	(3)	Market approach	Longer dated forward curve prices	$0.10-$0.53	$0.27	Per gallon
Natural gas	$	(1)	Market approach	Longer dated forward curve prices	$1.63-$2.50	$1.99	Per MMBtu

(a)Unobservable inputs were weighted by the instrument's notional amounts.

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

18

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

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 relationships with quoted market prices.

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 fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. The carrying value of borrowings under the Credit Agreement and the Securitization Facility approximate fair value as their interest rates are based on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of March 31, 2020 and December 31, 2019, the carrying value and fair value of our total debt, including current maturities, were as follows:

		March 31, 2020				December 31, 2019
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)
Total debt		$	5,936	$	4,252	$	5,936	$	6,130

(a) Excludes unamortized issuance costs and finance lease liabilities.

12. Leases

We have operating leases for transportation agreements, office space, vehicles, and field equipment. We have finance leases for field equipment and vehicles. Our leases have remaining lease terms ranging from less than one year to 21 years, some of which may include options to extend leases up to 20 years, and some of which may include options to terminate the leases in less than one year. Extension options on certain compressors and field equipment were included in the lease terms used to calculate our operating lease assets and liabilities as it is reasonably certain that we exercise those options. Operating and finance leases are included on our condensed consolidated balance sheet as follows:

	Location in Condensed Consolidated Balance Sheet	As of
		March 31, 2020		December 31, 2019
		(millions)
Assets
Operating lease assets	Operating lease assets	$	98	$	107
Finance lease assets	Property, plant and equipment	21		25
Total right of use assets		119		132
Liabilities
Current liabilities
Operating lease liabilities	Other current liabilities	$	23	$	24
Finance lease liabilities	Current debt	3		3
Noncurrent liabilities
Operating lease liabilities	Operating lease liabilities	$	83	$	88
Finance lease liabilities	Long-term debt	21		22
Total lease liabilities		$	130	$	137

Variable lease costs primarily consist of common area maintenance on our office spaces and variable transportation costs. Finance lease cost was immaterial for the three months ended March 31, 2020 and 2019, respectively. The components of lease expense are as follows:

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DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

	Location in Condensed Consolidated Statement of Operations	Three Months Ended March 31,
		2020		2019
		(millions)
Operating lease cost	Operating and maintenance expense	$	8	$	6
Variable lease cost	Operating and maintenance expense	2		2
Short term lease cost	Operating and maintenance expense	1		1
Total lease cost		$	11	$	9

Maturities of operating and finance lease liabilities under non-cancelable leases as of March 31, 2020 are as follows:

	Future Minimum Lease Payments as of March 31, 2020
	Operating Leases		Finance Leases
	(millions)
2020 - remainder	$	20	$	4
2021	25		4
2022	22		4
2023	17		4
2024	9		3
Thereafter	29		8
Total lease payments	$	122	$	27
Less imputed interest	(16)		(3)
Total lease liabilities	$	106	$	24

Supplemental cash flow information related to leases is as follows:

	Three Months Ended March 31,
	2020			2019
	(millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	7		$	6
Operating cash flows from finance leases	1			—
Right-of-use assets obtained in exchange for operating lease obligations:	$	—		$	6
Other information related to operating leases as follows:
Weighted average remaining lease term	6 years			6 years
Weighted average discount rate	4.00		%	4.00		%
Other information related to finance leases as follows:
Weighted average remaining lease term	6 years			—
Weighted average discount rate	3.00		%	—		%

20

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

13. Debt

	March 31, 2020		December 31, 2019
	(millions)
Senior notes:
Issued March 2010, interest at 5.350% payable semi-annually, due March 2020 (a)	$	—	$	600
Issued September 2011, interest at 4.750% payable semi-annually, due September 2021	500		500
Issued March 2012, interest at 4.950% payable semi-annually, due April 2022	350		350
Issued March 2013, interest at 3.875% payable semi-annually, due March 2023	500		500
Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025	825		825
Issued May 2019, interest at 5.125% payable semi-annually, due May 2029	600		600
Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)	300		300
Issued October 2006, interest at 6.450% payable semi-annually, due November 2036	300		300
Issued September 2007, interest at 6.750% payable semi-annually, due September 2037	450		450
Issued March 2014, interest at 5.600% payable semi-annually, due April 2044	400		400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043	550		550
Credit agreement:
Revolving credit facility, weighted-average variable interest rate of 2.157%, as of March 31, 2020, due December 2024	800		200
Accounts receivable securitization facility:
Accounts receivable securitization facility, weighted-average variable interest rate of 1.88% as of March 31, 2020, due August 2022	350		350
Fair value adjustments related to interest rate swap fair value hedges (a)	19		19
Unamortized issuance costs	(36)		(37)
Unamortized discount, net	(8)		(8)
Finance lease liabilities	24		25
Total debt	5,924		5,924
Current finance lease liabilities	3		3
Current debt	—		600
Total long-term debt	$	5,921	$	5,321

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

Senior Notes and Junior Subordinated Notes

Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on their respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our Credit Agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to 5 consecutive years. The underwriters’ fees and related expenses are recorded in our condensed consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

21

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

Credit Agreement

We are a party to a $1.4 billion unsecured revolving Credit Agreement, which matures on December 9, 2024. The Credit Agreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million, subject to requisite lender approval. The Credit Agreement may be extended for up to two additional one-year periods subject to requisite lender approval. Loans under the Credit Agreement may be used for working capital and other general partnership purposes including acquisitions.

The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed 5.00 to 1.0 provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement), the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of the three consecutive fiscal quarters, including the fiscal quarter in which the Qualified Acquisition occurs.

Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.35% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1.00%, plus (b) an applicable margin of 0.35% based on our current credit rating. The Credit Agreement incurs an annual facility fee of 0.275% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.4 billion revolving credit facility.

As of March 31, 2020, we had unused borrowing capacity of $586 million, net of $14 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by the unused borrowing capacity of $586 million as of March 31, 2020. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the December 9, 2024 maturity date.

Accounts Receivable Securitization Facility

The Securitization Facility provides up to $350 million of borrowing capacity through August 2022 at LIBOR market index rates plus a margin. Under this Securitization Facility, certain of the Partnership’s wholly owned subsidiaries sell or contribute receivables to another of the Partnership’s consolidated subsidiaries, DCP Receivables LLC (“DCP Receivables”), a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility. 

DCP Receivables’ sole activity consists of purchasing receivables from the Partnership’s wholly owned subsidiaries that participate in the Securitization Facility and providing these receivables as collateral for DCP Receivables’ borrowings under the Securitization Facility.  DCP Receivables is a separate legal entity and the accounts receivable of DCP Receivables, up to the amount of the outstanding debt under the Securitization Facility, are not available to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. Any excess receivables are eligible to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. The amount available for borrowing may be limited by the availability of eligible receivables and other customary factors and conditions, as well as the covenants set forth in the Securitization Facility. As of March 31, 2020, DCP Receivables had $590 million of our accounts receivable securing borrowings of $350 million under the Securitization Facility.

The maturities of our debt as of March 31, 2020 are as follows:

	Debt Maturities
	(millions)
2021	500
2022	700
2023	500
2024	800
Thereafter	3,425
Total debt	$	5,925

22

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

14. Risk Management and Hedging Activities

Our 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 and a risk management committee (the “Risk Management Committee”), to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

Collateral

As of March 31, 2020, we had cash deposits of $35 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of March 31, 2020, we held letters of credit of $44 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.

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

Offsetting

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

	March 31, 2020						December 31, 2019
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount		Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount
	(millions)
Assets:
Commodity derivatives	$	305	$	—	$	305	$	34	$	—	$	34
Liabilities:
Commodity derivatives	$	(238)	$	—	$	(238)	$	(78)	$	—	$	(78)

23

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

 Summarized Derivative Information

The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2020 and December 31, 2019.

Balance Sheet Line Item	March 31, 2020		December 31, 2019		Balance Sheet Line Item	March 31, 2020		December 31, 2019
	(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	$	252	$	32	Unrealized losses on derivative instruments — current	$	(192)	$	(58)
Unrealized gains on derivative instruments — long-term	53		2		Unrealized losses on derivative instruments — long-term	(46)		(20)
Total	$	305	$	34	Total	$	(238)	$	(78)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2020:

	Interest Rate Cash Flow Hedges		Commodity Cash Flow Hedges		Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(2)	$	(6)	$	1	$	(7)
Net deferred (losses) gains in AOCI (ending balance)	$	(2)	$	(6)	$	1	$	(7)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1)	$	—	$	—	$	(1)

(a)Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2019:

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

(a)Relates to Discovery, an unconsolidated affiliate.

For the three months ended March 31, 2020 and 2019, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2020 and 2019, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

24

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

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

Commodity Derivatives: Statements of Operations Line Item		Three Months Ended March 31,
		2020		2019
	(millions)
Realized gains		$	18	$	27
Unrealized gains (losses)		134		(54)
Trading and marketing gains (losses), net		$	152	$	(27)

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

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

	March 31, 2020
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long Position (MMBtu)
2020	(1,410,000)	(27,659,800)	(25,009,803)	8,190,000
2021	(1,467,000)	(45,540,000)	(7,294,133)	4,325,000
2022	(107,000)	(13,687,500)	(104,842)	8,212,500
2023	—	—	—	7,300,000
2024	—	—	—	2,140,000
	March 31, 2019
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long (Short) Position (MMBtu)
2019	(1,191,000)	(32,148,650)	(26,987,090)	2,102,500
2020	(283,000)	(930,000)	(14,388,830)	3,660,000
2021	(100,000)	—	(5,516,168)	(3,650,000)
2022	—	—	(175)	—

15. Partnership Equity and Distributions

Common Units — During the three months ended March 31, 2020 and 2019, we issued no common units, pursuant to our at-the-market program. As of March 31, 2020, $750 million of common units remained available for sale pursuant to our at-the-market program.

25

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

Distributions — During the first quarter of 2020, the board of directors of our general partner approved a plan to reduce quarterly distributions to our common unitholders by 50% to $0.39 per unit, beginning with the first quarter 2020 distribution, payable in May 2020. The following table presents our cash distributions paid in 2020 and 2019:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
February 14, 2020	$	0.78	$	162
November 14, 2019	$	0.78	$	155
August 14, 2019	$	0.78	$	154
May 15, 2019	$	0.78	$	155
February 14, 2019	$	0.78	$	154
Distributions to Series A Preferred unitholders
December 16, 2019	$	36.875	$	19
June 17, 2019	$	36.875	$	18
Distributions to Series B Preferred unitholders
March 16, 2020	$	0.4922	$	3
December 16, 2019	$	0.4922	$	4
September 16, 2019	$	0.4922	$	3
June 17, 2019	$	0.4922	$	3
March 15, 2019	$	0.4922	$	3
Distributions to Series C Preferred unitholders
January 15, 2020	$	0.4969	$	2
October 15, 2019	$	0.4969	$	2
July 15, 2019	$	0.4969	$	3
April 15, 2019	$	0.4969	$	2
January 15, 2019	$	0.5576	$	2

16. Net Income or Loss per Limited Partner Unit

Prior to the equity restructuring transaction, we used the two-class method when calculating the net income unit applicable to limited partners, because we had more than one participating security consisting of limited partner common units, general partner units and IDRs. Subsequent to the equity restructuring transaction that occurred on November 6, 2019, our general partner and its IDRs no longer participate in earnings or distributions.

There were 350,820 restricted phantom units outstanding as of March 31, 2020 that were excluded from the calculation of diluted net loss per unit for the periods presented because including them would have been anti-dilutive. We have the ability to elect to settle restricted phantom units at our discretion in either cash or common units. For units granted during 2020, we have the ability and intent to settle vested units through the issuance of common units.

26

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

17. Commitments and Contingent Liabilities

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

Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (i) general liability insurance covering third-party exposures; (ii) statutory workers’ compensation insurance; (iii) automobile liability insurance for all owned, non-owned and hired vehicles; (iv) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (v) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (vi) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, pipeline safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) regulatory bodies and communities, and through litigation, on hydraulic fracturing and the real or perceived environmental or public health impacts of this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, (iii) state and federal regulatory officials regarding the emission of greenhouse gases and other air emissions, which could impose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.

The following pending proceedings involve governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment. It is not possible for us to predict the final outcome of these pending proceedings; however, we do not expect the outcome of one or more of these proceedings to have a material adverse effect to our results of operations, financial position, or cash flows:

•In 2018, the New Mexico Environment Department (“NMED”) issued two separate Notices of Violation (“NOV”) relating to upset and malfunction event emissions at two of our gas processing plants. Following information exchanges and discussions with NMED regarding the events and the propriety of the alleged violations, in February 2019 we entered into preliminary settlement agreements to resolve the alleged violations under each NOV for administrative penalties approximating $150,000 and $142,000, respectively. We intend to mitigate a portion of each administrative penalty through the implementation of environmentally beneficial projects.

•In 2018, the Colorado Department of Public Health and Environment (“CDPHE”) issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants that we self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the plant's air permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as an economic benefit payment generally covering the period when the flare was required to be included in the facility air permit, in a combined amount expected to be between approximately $375,000 and $460,000. We are still evaluating and holding discussions with CDPHE as to the foregoing amounts and proposed settlement terms.

27

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

•In January 2019, CDPHE issued a Compliance Advisory in relation to an improperly configured facility flare meter, which failed to accurately track air emissions from the flare at one of our gas processing plants resulting in the flare exceeding its permitted emissions limits. Following information exchanges and discussions with CDPHE, a resolution was agreed upon in December 2019 that included DCP completing a project to reduce levels of vapors directed to the flare, amending the air permit, and paying an administrative penalty of approximately $37,000, and making expenditures on an environmentally beneficial project of approximately $149,000. DCP made the required payment and expenditures in the first quarter of 2020 and this proceeding is now complete.

18. Business Segments

Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 of the Notes to Consolidated Financial Statements in “Financial Statements and Supplementary Data” included as Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2019.

Our Logistics and Marketing segment includes transporting, trading, marketing, storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering condensate. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the Eliminations column.

The following tables set forth our segment information: 

Three Months Ended March 31, 2020: 

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	1,358	$	913	$	—	$	(614)	$	1,657
Gross margin (a)	$	111	$	400	$	—	$	—	$	511
Operating and maintenance expense	(7)		(142)		(4)		—		(153)
Depreciation and amortization expense	(3)		(89)		(7)		—		(99)
General and administrative expense	(2)		(3)		(51)		—		(56)
Asset impairments	—		(746)		—		—		(746)
Other expense, net	—		(3)		—		—		(3)
Earnings from unconsolidated affiliates	137		(61)		—		—		76
Interest expense	—		—		(78)		—		(78)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	236	$	(644)	$	(141)	$	—	$	(549)
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	236	$	(645)	$	(141)	$	—	$	(550)
Non-cash derivative mark-to-market (b)	$	42	$	92	$	—	$	—	$	134
Non-cash lower of cost or net realizable value adjustments	$	4	$	—	$	—	$	—	$	4
Capital expenditures	$	1	$	67	$	1	$	—	$	69
Investments in unconsolidated affiliates, net	$	34	$	—	$	—	$	—	$	34

28

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

Three Months Ended March 31, 2019:

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	2,045	$	1,288	$	—	$	(1,134)	$	2,199
Gross margin (a)	$	58	$	337	$	—	$	—	$	395
Operating and maintenance expense	(9)		(165)		(4)		—		(178)
Depreciation and amortization expense	(3)		(93)		(7)		—		(103)
General and administrative expense	(3)		(6)		(58)		—		(67)
Other expense, net	—		(5)		—		—		(5)
Loss on sale of assets, net	(9)		—		—		—		(9)
Earnings from unconsolidated affiliates	113		—		—		—		113
Interest expense	—		—		(69)		—		(69)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	147	$	68	$	(139)	$	—	$	76
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	147	$	67	$	(139)	$	—	$	75
Non-cash derivative mark-to-market (b)	$	(18)	$	(36)	$	—	$	—	$	(54)
Non-cash lower of cost or net realizable value adjustments	$	5	$	—	$	—	$	—	$	5
Capital expenditures	$	14	$	165	$	3	$	—	$	182
Investments in unconsolidated affiliates, net	$	131	$	—	$	—	$	—	$	131

	March 31,		December 31,
	2020		2019
	(millions)
Segment long-term assets:
Gathering and Processing	$	8,101	$	8,904
Logistics and Marketing	3,861		3,848
Other (c)	268		295
Total long-term assets	12,230		13,047
Current assets	958		1,080
Total assets	$	13,188	$	14,127

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

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

(c)Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.

29

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2020 and 2019 - (Continued)

(Unaudited)

19. Supplemental Cash Flow Information

	Three Months Ended March 31,
	2020		2019
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	88	$	65
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	16	$	40
Other non-cash activities:
Operating lease assets arising from the implementation of Topic 842	$	—	$	84
Right-of-use assets obtained in exchange for operating and finance lease liabilities	$	—	$	6

20. Subsequent Events

On April 21, 2020, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.39 per common unit. The distribution will be paid on May 15, 2020 to unitholders of record on May 1, 2020.

On the same date, we announced that the board of directors of the General Partner declared a semi-annual distribution on our Series A Preferred Units of $36.875 per unit. The distribution will be paid on June 15, 2020 to unitholders of record on June 1, 2020.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and $0.4969 per unit, respectively. The Series B distributions will be paid on June 15, 2020 to unitholders of record on June 1, 2020. The Series C distribution will be paid on July 15, 2020 to unitholders of record on July 1, 2020.

On April 13th, 2020, we announced a 15% workforce reduction, which will result in $11 million of non-recurring expense in the second quarter of 2020.

30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our condensed consolidated financial statements and notes included elsewhere in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019.

Overview

We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. Our Logistics and Marketing segment includes transporting, trading, marketing and storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate.

General Trends and Outlook

In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects curtailing global operations and travel, quarantines, and an overall substantial slowdown of economic activity. A further downturn in global economic growth, or recessionary conditions in major geographic regions, will lead to continued reduced demand for gas and NGLs and negatively affect the market prices of our products, further materially and adversely affecting our business, results of operations and liquidity. The extent of the impact of the COVID-19 pandemic on our operational and financial performance is anticipated to be temporary, but there is uncertainty around the extent and duration. Management anticipates that the industry and economic impact of the pandemic will have a negative effect on our results of operations in 2020 and perhaps beyond, the degree to which these factors will impact our business remains uncertain and the related financial impact of any such disruption cannot be reasonably estimated at this time.

We have taken proactive measures to address the unprecedented COVID-19 pandemic to maintain essential business functions at our plants and critical infrastructure without disruptions. Our current continuity plan specifically addresses technology, communications, and remote operations. To protect our workforce, we have mandated that those employees who are able to work from home do so, while implementing additional safety guidelines at our plants for those that cannot. We continue to prioritize safe and reliable operations.

On March 6, 2020 negotiations to set and maintain output levels for oil and gas among the Organization of Petroleum Exporting Countries and allies including Russia (OPEC+) concluded without an agreement removing all previous limits on production. The ensuing oversupply has greatly decreased commodities prices and added volatility and uncertainty into the future price outlook for commodities. An agreement to reduce oil production was subsequently reached but commodity prices continue to remain weak.

The sustained deterioration in commodity prices and volumes, other market declines or a decline in our unit price, may negatively impact our results of operations, and may increase the likelihood of further non-cash impairment charges or non-cash lower of cost or net realizable value inventory adjustments.

To address the extraordinary and volatile market conditions, we announced a distribution reduction of 50%, resulting in $325 million of cash to be used to reduce leverage and strengthen our balance sheet. Additionally, we announced cost and sustaining capital reductions of approximately $130 million and a reduction of growth capital expenditures by $450 million.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Our business is impacted by commodity prices and volumes. We mitigate a significant portion of commodity price risk on an overall Partnership basis by growing our fee based assets and by executing on our hedging program. Various factors impact both commodity prices and volumes, and as indicated in Item 3. “Quantitative and Qualitative Disclosures about Market Risk,” we have sensitivities to certain cash and non-cash changes in commodity prices. Commodity prices have declined substantially

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and experienced significant volatility in 2020. If commodity prices remain weak for a sustained period, our natural gas throughput and NGL volumes may be impacted, particularly as producers are curtailing or redirecting drilling.

Our long-term view is that commodity prices will be at levels that we believe will support sustained or increasing levels of domestic production. In recent years we have transformed our business to a more fee-based portfolio focused more on the logistics business to reduce commodity exposure. In addition, we use our strategic hedging program to further mitigate commodity price exposure. We expect future commodity prices will be influenced by tariffs and other global economic conditions, the level of North American production and drilling activity by exploration and production companies, the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil, and the severity of winter and summer weather.

Our business is primarily driven by the level of production of natural gas by producers and of NGLs from processing plants connected to our pipelines and fractionators. These volumes can be affected by, among other things, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection. Due to the COVID-19 pandemic, there has been a significant, unprecedented reduction in global demand for crude oil. This critical demand destruction has led to commodity price declines and storage capacity constraints. As a result, we expect meaningful volume declines to affect our earnings as producers reduce capital expenditures and shut-in wells.

We hedge commodity prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing segment. Drilling activity levels vary by geographic area; we will continue to target our strategy in geographic areas where we expect producer drilling activity.

We believe our contract structure with our producers provides us with significant protection from credit risk since we generally hold the product, sell it and withhold our fees prior to remittance of payments to the producer. Currently, our top 20 producers account for a majority of the total natural gas that we gather and process and of these top 20 producers, 6 have investment grade credit ratings.

The global economic outlook continues to be cause for concern for U.S. financial markets and businesses and investors alike. This uncertainty may contribute to volatility in financial and commodity markets.

We believe we are positioned to withstand current and future commodity price volatility as a result of the following:

•Our growing fee-based business represents a significant portion of our margins.

•We have positive operating cash flow from our well-positioned and diversified assets.

•We have a well-defined and targeted multi-year hedging program.

•We manage our disciplined capital growth program with a significant focus on fee-based agreements and projects with long-term volume outlooks.

•We believe we have a solid capital structure and balance sheet.

•We believe we have access to sufficient capital to fund our growth including excess distribution coverage and divestitures.

During 2020, our strategic objectives will continue to focus on maintaining stable Distributable Cash Flows (a non-GAAP measure defined in “Reconciliation of Non-GAAP Measures - Distributable Cash Flows”) from our existing assets and executing on opportunities to sustain our long-term Distributable Cash Flows. We believe the key elements to stable Distributable Cash Flows are the diversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our hedged commodity position, the objective of which is to protect against downside risk in our Distributable Cash Flows. We will continue to pursue incremental revenue, cost efficiencies and operating improvements of our assets through process and technology improvements.

In response to our commitment to reduce growth capital spend in 2020, only necessary and strategic projects that are currently underway will continue. The remaining projects will be deferred and evaluated in the future. Some of our growth projects include the following:

•Within our Logistics and Marketing segment, we exercised an increased 50% ownership option for the Cheyenne Connector pipeline in October of 2019. The pipeline is expected to be in service in the second quarter of 2020.

•Front Range’s expansion to a capacity of 260 MBbls/d and Texas Express’ expansion to a capacity of 370 MBbls/d were placed into service in the first quarter of 2020.

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•Within our Gathering and Processing Segment, we are adding up to 225 MMcf/d of incremental DJ Basin processing capacity by mid-2020 via a capital efficient offload agreement.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2020 plan includes sustaining capital expenditures of approximately $60 million and expansion capital expenditures of approximately $150 million. Expansion capital expenditures include the construction of the Cheyenne Connector pipeline.

Recent Events

Reduction in Force

On April 13th, 2020, we announced a 15% workforce reduction, which will result in $11 million of non-recurring expense in the second quarter of 2020.

Common and Preferred Distributions

On April 21, 2020, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.39 per common unit. The distribution will be paid on May 15, 2020 to unitholders of record on May 1, 2020.

On the same date, we announced that the board of directors of the General Partner declared a semi-annual distribution on our Series A Preferred Units of $36.875 per unit. The distribution will be paid on June 15, 2020 to unitholders of record on June 1, 2020.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and 0.4969 per unit, respectively. The Series B distributions will be paid on June 15, 2020 to unitholders of record on June 1, 2020. The Series C distribution will be paid on July 15, 2020 to unitholders of record on July 1, 2020.

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2020 and 2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three Months Ended March 31,				Variance 2020 vs. 2019
		2020		2019		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues (a):
Logistics and Marketing		$	1,358	$	2,045	$	(687)	(34)	%
Gathering and Processing		913		1,288		(375)		(29)	%
Inter-segment eliminations		(614)		(1,134)		(520)		(46)	%
Total operating revenues		1,657		2,199		(542)		(25)	%
Purchases and related costs
Logistics and Marketing		(1,247)		(1,987)		(740)		(37)	%
Gathering and Processing		(513)		(951)		(438)		(46)	%
Inter-segment eliminations		614		1,134		(520)		(46)	%
Total purchases		(1,146)		(1,804)		(658)		(36)	%
Operating and maintenance expense		(153)		(178)		(25)		(14)	%
Depreciation and amortization expense		(99)		(103)		(4)		(4)	%
General and administrative expense		(56)		(67)		(11)		(16)	%
Asset impairments		(746)		—		746		*
Other expense, net		(3)		(5)		(2)		(40)	%
Loss on sale of assets, net		—		(9)		(9)		*
Earnings from unconsolidated affiliates (b)		76		113		(37)		(33)	%
Interest expense		(78)		(69)		9		13	%
Income tax expense		(1)		(1)		—		—	%
Net income attributable to noncontrolling interests		(1)		(1)		—		—	%
Net (loss) income attributable to partners		$	(550)	$	75	$	(625)	*
Other data:
Gross margin (c):
Logistics and Marketing		$	111	$	58	$	53	91	%
Gathering and Processing		400		337		63		19	%
Total gross margin		$	511	$	395	$	116	29	%
Non-cash commodity derivative mark-to-market		$	134	$	(54)	$	188	*
NGL pipelines throughput (MBbls/d) (d)		677		668		9		1	%
Gas pipelines throughput (TBtu/d) (d)		0.76		0.25		0.51		*
Natural gas wellhead (MMcf/d) (d)		4,940		4,938		2		—	%
NGL gross production (MBbls/d) (d)		404		436		(32)		(7)	%

* Percentage change is not meaningful.

(a)Operating revenues include the impact of trading and marketing gains (losses), net.

(b)Earnings for Sand Hills pipeline, Southern Hills pipeline, Front Range pipeline, Gulf Coast Express pipeline, Texas Express pipeline and Mont Belvieu 1 fractionator include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

(c)Gross margin consists of total operating revenues less purchases and related costs. Segment gross margin for each segment consists of total operating revenues for that segment less purchases and related costs for that segment. Please read “Reconciliation of Non-GAAP Measures”.

(d)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead and throughput volumes and NGL production.

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Three Months Ended March 31, 2020 vs. Three Months Ended March 31, 2019

Total Operating Revenues — Total operating revenues decreased $542 million in 2020 compared to 2019 primarily as a result of the following:

•$687 million decrease for our Logistics and Marketing segment primarily due to lower commodity prices, partially offset by higher gas and NGL sales volumes and favorable commodity derivative activity; and

•$375 million decrease for our Gathering and Processing segment primarily due to lower commodity prices and decreased volumes in the Midcontinent region, partially offset by favorable commodity derivative activity, increased volume from growth projects in the DJ Basin, and increased volumes in the Permian region.

These decreases were partially offset by:

•$520 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity prices partially offset by higher gas and NGL sales volumes.

Total Purchases — Total purchases decreased $658 million in 2020 compared to 2019 primarily as a result of the following:

•$740 million decrease for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$438 million decrease for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These decreases were partially offset by:

•$520 million change in inter-segment eliminations, for the reasons discussed above.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2020 compared to 2019 primarily as a result of decreased base operating costs in the Permian and Midcontinent regions, partially offset by an increase in reliability spending.

General and Administrative Expense — General and administrative expense decreased in 2020 compared to 2019 primarily as a result of employee benefits.

Asset Impairments — Asset impairments in 2020 relate to long-lived assets in the Permian and South regions and goodwill in our North region.

Loss on Sale of Assets, net — The loss on sale of assets in 2019 represents the sale of our wholesale propane business.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2020 compared to 2019 primarily as a result of an impairment in our equity investment in Discovery, partially offset by higher Permian volumes on the Sand Hills pipeline due to increased capacity and the Gulf Coast Express pipeline coming online.

Interest Expense — Interest expense increased in 2020 compared to 2019 primarily as a result of higher average outstanding debt balances and lower capitalized interest due to projects placed in service.

Net (Loss) Income Attributable to Partners — Net (loss) income attributable to partners decreased in 2020 compared to 2019 for the reasons discussed above.

Gross Margin — Gross margin increased $116 million in 2020 compared to 2019 primarily as a result of the following:

•$63 million increase for our Gathering and Processing segment primarily related to favorable commodity derivative activity, increased volume from growth projects in the DJ Basin and increased volumes in the Permian region, partially offset by lower commodity prices, lower volumes in the Midcontinent region partially due to asset sales and lower margins in certain regions; and

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•$53 million increase for our Logistics and Marketing segment primarily related to favorable commodity derivative activity and higher NGL marketing and gas storage margins, partially offset by the sale of our wholesale propane business in 2019 and lower gas marketing margins due to less favorable commodity spreads primarily associated with Guadalupe in 2020.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

Earnings from investments in unconsolidated affiliates were as follows:

	Three Months Ended March 31,
	2020		2019
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	68
DCP Southern Hills Pipeline, LLC	20		23
Front Range Pipeline LLC	11		7
Gulf Coast Express LLC	16		—
Texas Express Pipeline LLC	4		5
Mont Belvieu Enterprise Fractionator	3		4
Mont Belvieu 1 Fractionator	3		4
Discovery Producer Services LLC	(61)		—
Other	2		2
Total earnings from unconsolidated affiliates	$	76	$	113

Distributions received from unconsolidated affiliates were as follows:

	Three Months Ended March 31,
	2020		2019
	(millions)
DCP Sand Hills Pipeline, LLC	$	79	$	76
DCP Southern Hills Pipeline, LLC	22		25
Front Range Pipeline LLC	12		6
Gulf Coast Express LLC	21		—
Texas Express Pipeline LLC	5		5
Mont Belvieu Enterprise Fractionator	3		1
Mont Belvieu 1 Fractionator	4		5
Discovery Producer Services LLC	6		5
Other	1		1
Total distributions from unconsolidated affiliates	$	153	$	124

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Results of Operations — Logistics and Marketing Segment

Operating Data
				Three Months Ended March 31, 2020
System	Approximate System Length (Miles)	Approximate Throughput Capacity (MBbls/d) (a)	Approximate Gas Throughput Capacity (Bcf/d) (a)	Pipeline Throughput (MBbls/d) (a)	Pipeline Throughput (TBtus/d) (a)
Sand Hills pipeline	1,400	333	—	322	—
Southern Hills pipeline	950	128	—	93	—
Front Range pipeline	450	50	—	60	—
Texas Express pipeline	600	28	—	20	—
Other NGL pipelines (a)	1,150	321	—	182	—
Gulf Coast Express pipeline	500	—	0.50	—	0.51
Guadalupe pipeline	600	—	0.25	—	0.25
Pipelines total	5,650	860	0.75	677	0.76

(a)Represents total capacity or total volumes allocated to our proportionate ownership share.

The results of operations for our Logistics and Marketing segment are as follows:

		Three Months Ended March 31,				Variance 2020 vs. 2019
		2020		2019		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	1,294	$	2,040	$	(746)	(37)	%
Transportation, processing and other		13		12		1		8	%
Trading and marketing gains (losses), net		51		(7)		58		*
Total operating revenues		1,358		2,045		(687)		(34)	%
Purchases and related costs		(1,247)		(1,987)		(740)		(37)	%
Operating and maintenance expense		(7)		(9)		(2)		(22)	%
Depreciation and amortization expense		(3)		(3)		—		—	%
General and administrative expense		(2)		(3)		(1)		(33)	%
Earnings from unconsolidated affiliates (a)		137		113		24		21	%
Loss on sale of assets, net		—		(9)		(9)		*
Segment net income attributable to partners		$	236	$	147	$	89	61	%
Other data:
Segment gross margin (b)		$	111	$	58	$	53	91	%
Non-cash commodity derivative mark-to-market		$	42	$	(18)	$	60	*
NGL pipelines throughput (MBbls/d) (c)		677		668		9		1	%
Gas pipelines throughput (TBtu/d) (c)		0.76		0.25		0.51		*

* Percentage change is not meaningful.

(a)Earnings for Sand Hills pipeline, Southern Hills pipeline, Front Range pipeline, Gulf Coast Express pipeline, Texas Express pipeline and Mont Belvieu 1 fractionator include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

(b)Segment gross margin consists of total operating revenues less purchases and related costs. Please read “Reconciliation of Non-GAAP Measures”.

(c)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volume.

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Three Months Ended March 31, 2020 vs. Three Months Ended March 31, 2019

Total Operating Revenues — Total operating revenues decreased $687 million in 2020 compared to 2019, primarily as a result of the following:

•$778 million decrease as a result of lower commodity prices before the impact of derivative activity.

This decrease was partially offset by:

•$58 million increase as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative gains of $60 million due to movements in forward prices of commodities in 2020, partially offset by a decrease in realized cash settlement gains of $2 million;

•$32 million increase attributable to higher gas and NGL sales volumes; and

•$1 million increase in transportation, processing and other.

Purchases and Related Costs — Purchases and related costs decreased $740 million in 2020 compared to 2019, as a result of the commodity price and volume changes discussed above.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2020 compared to 2019, primarily as a result of higher Permian volumes on the Sand Hills pipeline due to increased capacity and the Gulf Coast Express pipeline coming online.

Loss on Sale of Assets, net — The loss on sale of assets in 2019 represents the sale of our wholesale propane business.

Segment Gross Margin — Segment gross margin increased $53 million in 2020 compared to 2019, primarily as a result of the following:

•$58 million increase as a result of commodity derivative activity as discussed above; and

•$10 million increase as a result of increased NGL marketing and gas storage margins.

These increases were partially offset by:

•$8 million decrease due to the sale of our wholesale propane business; and

•$7 million decrease primarily as a result of decreased gas marketing margins due to less favorable commodity spreads in 2020.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2020 compared to 2019, primarily as a result of the addition of our DJ Basin Southern Hills extension and increased volumes on the Front Range pipeline and other NGL pipelines, partially offset by decreased throughput on the Black Lake and Southern Hills pipelines.

Gas Pipelines Throughput — Gas throughput increased in 2020 compared to 2019, primarily as a result of Gulf Coast Express pipeline coming online.

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Results of Operations — Gathering and Processing Segment

Operating Data
				Three Months Ended March 31, 2020
Regions	Plants	Approximate Gathering and Transmission Systems (Miles)	Approximate Net Nameplate Plant Capacity (MMcf/d) (a)	Natural Gas Wellhead Volume (MMcf/d) (a)	NGL Production (MBbls/d) (a)
North	13	4,000	1,580	1,603	124
Permian	10	15,500	1,200	1,038	116
Midcontinent	7	24,500	1,145	960	68
South	12	7,000	2,235	1,339	96
Total	42	51,000	6,160	4,940	404

(a)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead volume and NGL production.

The results of operations for our Gathering and Processing segment are as follows:

		Three Months Ended March 31,				Variance 2020 vs. 2019
		2020		2019		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	713	$	1,205	$	(492)	(41)	%
Transportation, processing and other		99		103		(4)		(4)	%
Trading and marketing gains (losses), net		101		(20)		121		*
Total operating revenues		913		1,288		(375)		(29)	%
Purchases and related costs		(513)		(951)		(438)		(46)	%
Operating and maintenance expense		(142)		(165)		(23)		(14)	%
Depreciation and amortization expense		(89)		(93)		(4)		(4)	%
General and administrative expense		(3)		(6)		(3)		(50)	%
Asset impairments		(746)		—		746		*
Other expense, net		(3)		(5)		(2)		(40)	%
Loss from unconsolidated affiliates (a)		(61)		—		(61)		*
Segment net (loss) income		(644)		68		(712)		*
Segment net income attributable to noncontrolling interests		(1)		(1)		—		—	%
Segment net (loss) income attributable to partners		$	(645)	$	67	$	(712)	*
Other data:
Segment gross margin (b)		$	400	$	337	$	63	19	%
Non-cash commodity derivative mark-to-market		$	92	$	(36)	$	128	*
Natural gas wellhead (MMcf/d) (c)		4,940		4,938		2		—	%
NGL gross production (MBbls/d) (c)		404		436		(32)		(7)	%

* Percentage change is not meaningful.

(a)Earnings from unconsolidated affiliates includes our 40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference between the carrying amount of our investment and the underlying equity of the entity.

(b)Segment gross margin consists of total operating revenues, less purchases and related costs. Please read “Reconciliation of Non-GAAP Measures”.

(c)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead volume and NGL production.

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Three Months Ended March 31, 2020 vs. Three Months Ended March 31, 2019

Total Operating Revenues — Total operating revenues decreased $375 million in 2020 compared to 2019, primarily as a result of the following:

•$536 million decrease attributable to lower commodity prices, before the impact of derivative activity;

•$66 million decrease primarily as a result of decreased volumes in the Midcontinent region; and

•$4 million decrease in transportation, processing and other.

These decreases were partially offset by:

•$121 million increase as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative gains of $128 million due to movements in forward prices of commodities in 2020, partially offset by a decrease in realized cash settlement gains of $7 million; and

•$110 million increase primarily as a result of increased volume from growth projects in the DJ Basin and increased volumes in the Permian region.

Purchases and Related Costs — Purchases and related costs decreased $438 million in 2020 compared to 2019, as a result of the commodity price and volume changes discussed above.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2020 compared to 2019, primarily as a result of decreased base operating costs in the Permian and Midcontinent regions, partially offset by an increase in reliability spending.

Asset Impairments — Asset impairments in 2020 relate to long-lived assets in the Permian and South regions and goodwill in the North region.

Loss from Unconsolidated Affiliates — Loss from unconsolidated affiliates primarily relates to an impairment of our equity investment in Discovery.

Segment Gross Margin — Segment gross margin increased $63 million in 2020 compared to 2019, primarily as a result of the following:

•$121 million increase as a result of commodity derivative activity as discussed above; and

•$12 million increase primarily as a result of increased volume from growth projects in the DJ Basin and increased volumes in the Permian region, partially offset by lower volumes in the Midcontinent region partially due to asset sales and lower margins in certain regions.

These increases were partially offset by:

•$70 million decrease as a result of lower commodity prices.

Total Wellhead — Natural gas wellhead increased in 2020 compared to 2019 reflecting higher volumes in the North and Permian regions, partially offset by lower volumes in the Midcontinent region.

NGL Gross Production — NGL gross production decreased in 2020 compared to 2019 primarily as a result of ethane rejection across several regions, partially offset by growth projects in the DJ Basin and higher volumes in the Permian region.

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Liquidity and Capital Resources

We expect our sources of liquidity to include:

•cash generated from operations;

•cash distributions from our unconsolidated affiliates;

•borrowings under our Credit Agreement;

•proceeds from asset rationalization;

•debt offerings;

•borrowings under term loans, securitization agreements or other credit facilities;

•issuances of additional common units, preferred units or other securities; and

•letters of credit.

We anticipate our more significant uses of resources to include:

•quarterly distributions to our common unitholders and distributions to our preferred unitholders;

•payments to service our debt;

•growth capital expenditures;

•contributions to our unconsolidated affiliates to finance our share of their capital expenditures;

•business and asset acquisitions; and

•collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements.

We believe prices will remain volatile and volumes will decline in the near term due to the COVID-19 pandemic and its impact on the U.S. economy and this will have an indirect impact on our leverage. While we are taking actions to mitigate the impact, our leverage may increase as a result of these actions. Further, it is possible we may not maintain our current credit ratings or compliance with the financial covenants contained in the Credit Agreement and other debt instruments due to the uncertainty in commodity pricing and volume declines and their effect on our operations. Failure to comply with our financial covenants, if not waived, would result in an event of default and potential acceleration of outstanding debt. We believe that the actions we are taking and may take in the future will avoid any event of default.

To address the extraordinary and volatile market conditions, we recently announced a distribution reduction of 50%, resulting in $325 million of cash which we currently intend to use to reduce leverage and strengthen our balance sheet. Additionally, we announced cost and sustaining capital reductions of approximately $130 million and a reduction of growth capital expenditures by $450 million.

We believe that cash generated from these sources and actions will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and quarterly cash distributions for the next twelve months.

Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, impact our credit ratings, raise our financing costs, as well as impact our compliance with the financial covenants contained in the Credit Agreement and other debt instruments.

Credit Agreement — As of March 31, 2020, we had unused borrowing capacity of $586 million, net of $14 million of letters of credit and $800 million borrowings under the Credit Agreement. We repaid at maturity $600 million of our 5.35% Senior Notes due March 2020 using borrowings under the Credit Agreement. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. As of May 1, 2020, we had approximately $558 million of unused borrowing capacity under the Credit Agreement, net of $14 million of letters of credit and $828 million of borrowings under the Credit Agreement.

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Accounts Receivable Securitization Facility — As of March 31, 2020, we had $350 million of outstanding borrowings under our Securitization Facility at LIBOR market index rates plus a margin. As of May 1, 2020, we had approximately $331 million of outstanding borrowings under our Securitization Facility.

Issuance of Securities — In November 2017, we filed a shelf registration statement with the SEC that became effective upon filing and allows us to issue an indeterminate amount of common units, preferred units, and debt securities.

In August 2017, we filed a shelf registration statement with the SEC which allows us to issue up to $750 million in common units pursuant to our at-the-market program. During the three months ended March 31, 2020, we did not issue any common units pursuant to this registration statement, and $750 million remained available for future sales.

Guarantee of Registered Debt Securities — The consolidated financial statements of DCP Midstream, LP, or “parent guarantor”, include the accounts of DCP Midstream Operating LP, or “subsidiary issuer”, which is a 100% owned subsidiary, and all other subsidiaries which are all non-guarantor subsidiaries. The parent guarantor has agreed to fully and unconditionally guarantee the senior notes. The entirety of the Company’s operating assets and liabilities, operating revenues, expenses and other comprehensive income exist at its non-guarantor subsidiaries, and the parent guarantor and subsidiary issuer have no assets, liabilities or operations independent of their respective financing activities and investments in non-guarantor subsidiaries. All covenants in the indentures governing the notes limit the activities of subsidiary issuer, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to parent guarantor.

In March 2020, the SEC issued a final rule, Financial Disclosures About Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant's Securities, which amends the disclosure requirements related to certain registered securities which require separate financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. Alternative disclosures are available for each subsidiary/parent issuer/guarantor when they are consolidated and the parent company either issues or guarantees, on a full and unconditional basis, the guaranteed securities. If a registrant qualifies for alternative disclosure, the registrant may omit summarized financial information when not material and provide narrative disclosure of the guarantor structure, including terms and conditions of the guarantees.

The Company qualifies for alternative disclosure because the combined financial information of the subsidiary issuer and parent guarantor, excluding investments in subsidiaries that are not issuers or guarantors, reflect no material assets, liabilities or results of operations apart from their respective financing activities and investments in non-guarantor subsidiaries. Therefore, the Company is no longer presenting condensed consolidating financial information for its parent guarantor, subsidiary issuer, and non-guarantor subsidiaries. The only assets, liabilities and results of operations of the subsidiary issuer and parent guarantor on a combined basis, independent of their respective investments in non-guarantor subsidiaries are:

•Accounts payable and other current liabilities of $69 million and $83 million as of March 31, 2020 and December 31, 2019, respectively;

•Balances related to debt of $5.575 billion and $5.549 billion as of March 31, 2020 and December 31, 2019, respectively; and

•Interest expense, net of $75 million and $67 million for the three months ended March 31, 2020 and March 31, 2019, respectively.

Commodity Swaps and Collateral — Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. For additional information regarding our derivative activities, please read Item 3. “Quantitative and Qualitative Disclosures about Market Risk” contained herein.

When we enter into commodity swap contracts we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a pricing point at which our swap contracts will meet the collateral thresholds as we may transact

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multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis.

Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced in part by our quarterly distributions, which are required under the terms of our Partnership Agreement based on Available Cash, as defined in the Partnership Agreement. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and other business factors that affect our net income and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, cash collateral we may be required to post with counterparties to our commodity derivative instruments, borrowings of and payments on debt and the Securitization Facility, capital expenditures, and increases or decreases in other long-term assets. We expect that our future working capital requirements will be impacted by these same recurring factors.

We had working capital deficits of $8 million and $713 million as of March 31, 2020 and December 31, 2019, respectively, driven by current maturities of long term debt of $3 million and $603 million, respectively. We had a net derivative working capital surplus of $60 million as of March 31, 2020 and deficit of $26 million as of December 31, 2019.

As of March 31, 2020, we had $18 million in cash and cash equivalents, of which $1 million was held by consolidated subsidiaries we do not wholly own.

Cash Flow — Operating, investing and financing activities were as follows:

	Three Months Ended March 31,
	2020		2019
	(millions)
Net cash provided by operating activities	$	314	$	317
Net cash used in investing activities	$	(103)	$	(210)
Net cash used in financing activities	$	(171)	$	(107)

Three Months Ended March 31, 2020 vs. Three Months Ended March 31, 2019

Operating Activities — Net cash provided by operating activities decreased $3 million in 2020 compared to the same period in 2019. The changes in net cash provided by operating activities are attributable to our net (loss) income adjusted for non-cash charges and changes in working capital as presented in the condensed consolidated statements of cash flows. For additional information regarding fluctuations in our earnings and distributions from unconsolidated affiliates, please read “Results of Operations”.

Investing Activities — Net cash used in investing activities decreased $107 million in 2020 compared to the same period in 2019 primarily as a result of lower capital expenditures due to completed or deferred capital projects and lower investments in unconsolidated affiliates primarily related to the completion of construction of the Gulf Coast Express pipeline.

Financing Activities — Net cash used in financing activities increased $64 million in 2020 compared to the same period in 2019 primarily as a result of lower net proceeds of debt and higher distributions paid to limited partners following our IDR elimination and equity restructuring in 2019.

Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:

•Sustaining capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Sustaining capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and

•Expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings capacity. Expansion capital expenditures include acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines and well connects, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets).

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We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2020 plan includes sustaining capital expenditures of approximately $60 million, and expansion capital expenditures of approximately $150 million. Expansion capital expenditures include the construction of the Cheyenne Connector pipeline.

We intend to make cash distributions to our unitholders. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, to fund future acquisitions and capital expenditures.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, Securitization Facility and the issuance of additional debt and equity securities.

Cash Distributions to Unitholders — Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the Partnership Agreement. We made cash distributions to our common unitholders and general partner of $162 million and $154 million during the three months ended March 31, 2020 and 2019, respectively.

On April 21, 2020, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.39 per common unit. The distribution will be paid on May 15, 2020 to unitholders of record on May 1, 2020.

On the same date, we announced that the board of directors of the General Partner declared a semi-annual distribution on our Series A Preferred Units of $36.875 per unit. The distribution will be paid on June 15, 2020 to unitholders of record on June 1, 2020.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and 0.4969 per unit, respectively. The Series B distributions will be paid on June 15, 2020 to unitholders of record on June 1, 2020. The Series C distribution will be paid on July 15, 2020 to unitholders of record on July 1, 2020.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders. See Note 15. “Partnership Equity and Distributions” in the Notes to the Condensed Consolidated Financial Statements in Item 1. “Financial Statements.”

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Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of March 31, 2020, was as follows:

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(millions)
Debt (a)	$	7,808	$	264	$	1,834	$	410	$	5,300
Finance lease obligations	27		4		8		7		8
Operating lease obligations	122		20		47		26		29
Purchase obligations (b)	6,899		1,304		2,328		1,482		1,785
Other long-term liabilities (c)	159		—		33		2		124
Total	$	15,015	$	1,592	$	4,250	$	1,927	$	7,246

(a)Includes interest payments on debt securities that have been issued. These interest payments are $264 million, $484 million, $410 million, and $1,875 million for less than one year, one to three years, three to five years, and thereafter, respectively.

(b)Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction agreements for capital expenditures, various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including long-term fractionation and transportation agreements. For contracts where the price paid is based on an index or other market-based rates, the amount is based on the forward market prices or current market rates as of March 31, 2020. Purchase obligations exclude accounts payable, accrued taxes and other current liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(c)Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities and other miscellaneous liabilities recognized in the March 31, 2020 condensed consolidated balance sheet. The table above excludes non-cash obligations as well as $25 million of Executive Deferred Compensation Plan contributions and $2 million of long-term incentive plans as the amount and timing of any payments are not subject to reasonable estimation.

Off-Balance Sheet Obligations

As of March 31, 2020, we had no items that were classified as off-balance sheet obligations.

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Reconciliation of Non-GAAP Measures

Gross Margin and Segment Gross Margin — In addition to net income, we view our gross margin as an important performance measure of the core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.

We define gross margin as total operating revenues, less purchases and related costs, and we define segment gross margin for each segment as total operating revenues for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross margin and segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin and segment gross margin should not be considered an alternative to, or more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP.

Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings, (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives, (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Management believes these measures provide investors meaningful insight into results from ongoing operations.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.

Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess:

•financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure;

•viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and

•in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and finance sustaining capital expenditures.

Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings, (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives, (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted segment EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate adjusted segment EBITDA in the same manner.

Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP, including operating revenues, net income or loss attributable to partners, or any other measure of performance presented in accordance with GAAP.

Our gross margin, segment gross margin, adjusted EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner. The accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment EBITDA to their most directly comparable GAAP financial measures.

Distributable Cash Flow — We define Distributable Cash Flow as adjusted EBITDA, as defined above, less sustaining capital expenditures, net of reimbursable projects, less interest expense, less income attributable to preferred units, and certain other items. Sustaining capital expenditures are cash expenditures made to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and

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safety improvements. Sustaining capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets. Income attributable to preferred units represent cash distributions earned by the preferred units. Cash distributions to be paid to the holders of the preferred units assuming a distribution is declared by our board of directors, are not available to common unit holders. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. We compare the Distributable Cash Flow we generate to the cash distributions we expect to pay our partners. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.

Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner.

The following table sets forth our reconciliation of certain non-GAAP measures:

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		Three Months Ended March 31,
		2020		2019
Reconciliation of Non-GAAP Measures	(millions)
Reconciliation of net income attributable to partners to gross margin:
Net (loss) income attributable to partners		$	(550)	$	75
Interest expense		78		69
Income tax expense		1		1
Operating and maintenance expense		153		178
Depreciation and amortization expense		99		103
General and administrative expense		56		67
Asset impairments		746		—
Other expense, net		3		5
Earnings from unconsolidated affiliates		(76)		(113)
Loss on sale of assets, net		—		9
Net income attributable to noncontrolling interests		1		1
Gross margin		$	511	$	395
Non-cash commodity derivative mark-to-market (a)		$	134	$	(54)
Reconciliation of segment net income attributable to partners to segment gross margin:
Logistics and Marketing segment:
Segment net income attributable to partners		$	236	$	147
Operating and maintenance expense		7		9
Depreciation and amortization expense		3		3
General and administrative expense		2		3
Earnings from unconsolidated affiliates		(137)		(113)
Loss on sale of assets, net		—		9
Segment gross margin		$	111	$	58
Non-cash commodity derivative mark-to-market (a)		$	42	$	(18)
Gathering and Processing segment:
Segment net (loss) income attributable to partners		$	(645)	$	67
Operating and maintenance expense		142		165
Depreciation and amortization expense		89		93
General and administrative expense		3		6
Asset impairments		746		—
Other expense, net		3		5
Earnings from unconsolidated affiliates		61		—
Net income attributable to noncontrolling interests		1		1
Segment gross margin		$	400	$	337
Non-cash commodity derivative mark-to-market (a)		$	92	$	(36)

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

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		Three Months Ended March 31,
		2020		2019
	(millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:
Logistics and Marketing segment:
Segment net income attributable to partners (a)		$	236	$	147
Non-cash commodity derivative mark-to-market		(42)		18
Depreciation and amortization expense, net of noncontrolling interest		3		3
Distributions from unconsolidated affiliates, net of earnings		10		6
Loss on sale of assets, net		—		9
Other expense		1		—
Adjusted segment EBITDA		$	208	$	183
Gathering and Processing segment:
Segment net (loss) income attributable to partners		$	(645)	$	67
Non-cash commodity derivative mark-to-market		(92)		36
Depreciation and amortization expense, net of noncontrolling interest		89		92
Asset impairments		746		—
Distributions from unconsolidated affiliates, net of earnings		67		5
Other expense		3		5
Adjusted segment EBITDA		$	168	$	205

(a) We recognized lower of cost or net realizable value adjustments of $4 million and $5 million during the three months ended March 31, 2020 and 2019, respectively.

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Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in “Critical Accounting Policies and Estimates” within Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2019 and Note 2 of the Notes to Consolidated Financial Statements in “Financial Statements and Supplementary Data” included as Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2019. With the exception of updates to significant accounting policies discussed in Note 2 of this Quarterly Report on Form 10-Q, the accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three months ended March 31, 2020 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2019. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from the interim financial statements included in this Quarterly Report on Form 10-Q pursuant to the rules and regulations of the SEC, although we believe that the disclosures made are adequate to make the information not misleading. The unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the audited consolidated financial statements and notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2019.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2019.

The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering and processing operations. Our positions as of May 1, 2020 were as follows:

Commodity Swaps

Period	Commodity	Notional Volume - Short Positions	Reference Price	Price Range
April 2020 — December 2020	Natural Gas	(5,000) MMBtu/d	NYMEX Final Settlement Price (a)	$2.58-$2.59/MMBtu
January 2021 — December 2021	Natural Gas	(115,000) MMBtu/d	NYMEX Final Settlement Price (a)	$2.35-$2.43/MMBtu
January 2022 — December 2022	Natural Gas	(37,500) MMBtu/d	NYMEX Final Settlement Price (a)	$2.40-$2.41/MMBtu
April 2020 — December 2020	NGLs	(10,279) Bbls/d (d)	Mt.Belvieu (b)	$.51-$.62/Gal
January 2021 — December 2021	NGLs	(4,245) Bbls/d (d)	Mt.Belvieu (b)	$.53-$.60/Gal
April 2020 — December 2020	Crude Oil	(6,362) Bbls/d (d)	NYMEX crude oil futures (c)	$53.69-$62.25/Bbl
January 2021 — February 2022	Crude Oil	(2,537) Bbls/d (d)	NYMEX crude oil futures (c)	$52.47-$57.29/Bbl

(a)     NYMEX final settlement price for natural gas futures contracts.

(b)     The average monthly OPIS price for Mt. Belvieu TET/Non-TET.

(c) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).

(d) Average Bbls/d per time period.

Our sensitivities for 2020 as shown in the table below are estimated based on our average estimated commodity price exposure and commodity cash flow protection activities for the calendar year 2020, and exclude the impact of non-cash mark-to-market changes on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to mitigate a portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with our condensate, natural gas and NGL volumes that are currently unhedged.

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Commodity Sensitivities Net of Cash Flow Protection Activities  

	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(millions)
NGL prices	$	0.01	Gallon	$	2
Natural gas prices	$	0.10	MMBtu	$	7
Crude oil prices	$	1.00	Barrel	$	2

In addition to the linear relationships in our commodity sensitivities above, additional factors may cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a portion from percentage-of-proceeds and percentage-of-liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as commodity prices decline.

We estimate the following sensitivities related to the non-cash mark-to-market on our commodity derivatives associated with our open position on our commodity cash flow protection activities:

Non-Cash Mark-To-Market Commodity Sensitivities

	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market Impact (Decrease in Net Income Attributable to Partners)
				(millions)
NGL prices	$	0.01	Gallon	$	2
Natural gas prices	$	0.10	MMBtu	$	1
Crude oil prices	$	1.00	Barrel	$	2

While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.

The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments.

Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long-term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. Additionally, the level of NGL export demand may also have an impact on prices. We believe that future natural gas prices will be influenced by the level of North American production and drilling activity of exploration and production companies, the balance of trade between imports and exports of liquid natural gas and NGLs and the severity of winter and summer weather. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall relative to demand levels.

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

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

The following tables set forth additional information about our derivative instruments, used to mitigate a portion of our natural gas price risk associated with our inventory within our natural gas storage operations as of March 31, 2020:

Inventory 

Period ended	Commodity	Notional Volume -  Long Positions		Fair Value (millions)		Weighted Average Price
March 31, 2020	Natural Gas	10,895,924	MMBtu	$	21	$1.96/MMBtu

Commodity Swaps 

Period	Commodity	Notional Volume  - (Short)/Long Positions		Fair Value (millions)		Price Range
April 2020 — January 2021	Natural Gas	(16,900,000)	MMBtu	$	2	$1.67-$2.70/MMBtu
April 2020	Natural Gas	5,950,000	MMBtu	$	—	$1.61-$1.93/MMBtu

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the “Certifying Officers”), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of March 31, 2020, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of March 31, 2020, our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

Item 1. Legal Proceedings

The information provided in “Commitments and Contingent Liabilities” included in (a) Note 21 of the Notes to Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2019 and (b) Note 16 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q are incorporated herein by reference.

Item 1A. Risk Factors

An investment in our securities involves various risks. When considering an investment in us, careful consideration should be given to the risk factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019. There are no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2019, except as follows:

We face numerous risks related to the recent outbreak of COVID-19, which could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.

Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies around the world, including the oil, gas and NGL industry in which we operate. The rapid spread of the virus has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel, and other public health and safety measures. The extent to which COVID-19 impacts our operations will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the pandemic, additional or modified government actions, new information which may emerge concerning the severity of COVID-19, and the actions taken to contain the spread of COVID-19 and treat its impact, among others.

Some factors from the COVID-19 pandemic that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:

•third-party effects, including contractual and counterparty risk;

•supply/demand market and macro-economic forces;

•lower commodity prices;

•unavailable storage capacity and operational effects, including curtailments and shut-ins;

•decreased utilization and rates for our assets and services

•impact on liquidity and access to capital markets;

•workforce reductions and furloughs; and

•federal, state and local actions.

The COVID-19 pandemic continues to rapidly evolve, and the extent to which the pandemic may impact business, financial condition, liquidity, results of operations and prospects will depend highly on future developments, which are very uncertain and cannot be predicted with confidence. Additionally, the extent and duration of the impact of COVID-19 pandemic on our unit price is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our units, our unit prices may be more volatile, and our ability to raise capital could be impaired.

The ability or willingness of OPEC and other oil exporting nations to set, maintain and enforce production levels has a significant impact on oil, gas and NGL commodity prices, which could have a material adverse effect on our business, financial condition, liquidity and results of operations.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC member countries, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. In March 2020, members of OPEC+ met to discuss how to respond to the potential market effects of the COVID-19 pandemic. The meeting ended on March 6, 2020, as Saudi Arabia failed to convince Russia to accept a reduction in production to offset falling demand due to slowing economic activity during the COVID-19 pandemic. In response to Russia’s refusal to accept the production cut, Saudi Arabia announced an immediate reduction in its export prices and Russia announced that all previously agreed oil production cuts would expire on April 1, 2020. These actions led to an

53

immediate and steep decrease in global oil prices. In early April 2020, in response to significantly depressed global oil prices, 23 countries, led by Saudi Arabia, Russia and the United States, committed to withhold collectively 9.7 million barrels a day of oil from global markets, which constitutes over 13% of world oil production.

There can be no assurance that the production cuts will have the intended effects, including a stabilization of oil prices. The COVID-19 pandemic has destroyed global oil demand to an unprecedented degree, and there can be no assurance that the production cuts will be sufficient to prevent or mitigate an over-supplied oil market and further decreases in oil prices. Further, there are limited enforcement mechanisms related to the production cuts, and in connection with past production cuts OPEC has at times failed to enforce its own production limits with no official mechanism for punishing member countries that do not comply. There can be no assurance that OPEC member countries will abide by the quotas or that OPEC will enforce the quotas. Additionally, certain other countries that agreed to hold back production but are not OPEC member countries, were not asked to impose production cuts on their oil producers, but instead the decrease in production will be effectuated through market forces, as companies tend to cut production voluntarily when prices drop. For such countries, there can be no assurance that oil producers will react in the desired manner or that the market will behave as expected. Uncertainty regarding the effectiveness and enforcement of the production cuts is likely to lead to increased volatility in the supply and demand of oil, gas and NGLs and the price of oil, gas and NGLs, which could lead to continued reduced demand for oil, gas and NGLs and negatively affect the market prices of our products, all of which could materially and adversely affect our business, results of operations, financial condition and liquidity.

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Exhibit Number		Description
3.1	*	Certificate of Limited Partnership of DCP Midstream Partners, LP dated August 5, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP's Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on September 16, 2005).
3.2	*	Certificate of Amendment to Certificate of Limited Partnership of DCP Midstream Partners, LP dated January 11, 2017 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 17, 2017).
3.3	*	Fifth Amended and Restated Agreement of Limited Partnership of DCP Midstream, LP dated November 6, 2019 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2019).
10.1	+	Form of Strategic Performance Unit Grant Agreement under the DCP Midstream, LP 2016 Long-Term Incentive Plan.
10.2	+	Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream, LP 2016 Long-Term Incentive Plan.
10.3	+	DCP Services, LLC Amended and Restated Executive Severance Plan effective February 19, 2020.
22		List of Guaranteed Securities
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream, LP for the three months ended March 31, 2020, formatted in Inline XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive (Loss) Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statements of Changes in Equity, and (vi) the Notes to the Condensed Consolidated Financial Statements.
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

+ Denotes management contract or compensatory plan or arrangement.

55

SIGNATURES

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 thereunto duly authorized.

	DCP Midstream, LP
	By:	DCP Midstream GP, LP its General Partner
	By:	DCP Midstream GP, LLC its General Partner
Date: May 7, 2020	By:	/s/ Wouter T. van Kempen
		Name:	Wouter T. van Kempen
		Title:	President and Chief Executive Officer
			(Principal Executive Officer)
Date: May 7, 2020	By:	/s/ Sean P. O'Brien
		Name:	Sean P. O'Brien
		Title:	Group Vice President and Chief Financial Officer
			(Principal Financial Officer)

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EX-10.1

DCP Midstream, LP

2016 Long-Term Incentive Plan

Form of Strategic Performance Unit Award Agreement

Awardee:  __________

Award Date:   __________

(also known as Grant Date)

Performance Period:  __________

1.Award of Strategic Performance Units (also known as Grant). DCP Services, LLC (the “Company”) hereby grants to you Performance Awards hereafter referred to as Strategic Performance Units (“SPUs”) allocated as __________DCP common units under the DCP Midstream, LP Long-Term Incentive Plan (the “Plan”) on the terms and conditions set forth herein. The number of SPUs has been determined based on the average closing price of the DCP common units during the last twenty trading days immediately prior to the Performance Period Date and includes a tandem Dividend Equivalent Right (“DER”) grant with respect to each SPU. The Company will establish a DER bookkeeping account for you with respect to each SPU granted that shall be credited with an amount equal to the cash dividends, expressed in US dollars, made during the Performance Period with respect to the DCP common units. Unless otherwise defined herein, terms used, but not defined, in this Award Agreement shall have the same meaning as set forth in the Plan.

2.Performance Goals and Vesting.The SPUs are considered “Vested” once they are no longer forfeitable. The SPUs granted hereunder shall become Vested only if (i) the performance goals set forth in the “Performance Schedule” attached hereto are achieved at the end of the Performance Period and (ii) you have not ceased to be an Employee for any reason (a “Termination of Service”) prior to the end of the Performance Period, except as provided in Paragraph 3 below. To the extent the performance goals are not achieved, the SPUs shall be forfeited automatically at the end of the Performance Period without payment.

3.Contingent Vesting Events. You may become contingently Vested prior to the end of the Performance Period as provided below, but unless the performance goals for the Performance Period are achieved, you will not become entitled to a payment with respect to SPUs.

(a) Death, Disability, Retirement or Layoff. If you incur a Termination of Service after the first anniversary of your initial Award Date for the year as a result of your death, disability, Retirement or layoff, a percentage of your SPUs will become contingently Vested in a pro-rata share (rounded to the nearest whole SPU) based on the number of days in the Performance Period that have lapsed through the date of your Termination of Service over the total number of days in the Performance Period. The number of your SPUs that do not become contingently Vested as provided above will be forfeited automatically on the date of your Termination of Service without payment.

(b) Other Terminations of Service. If your Termination of Service occurs prior to the end of the Performance Period for any reason other than as provided in Paragraph 3(a) above, all of your SPUs and DERs shall be forfeited without payment automatically upon the date of your Termination of Service.

4.Payments.

(a) SPUs. As soon as administratively practicable after the last day of the Performance Period the Committee will determine whether, and the extent to which, the performance goals set forth on the Performance Schedule have been achieved and the number of your SPUs that have become Vested as a result of such achievement. The Company will then pay you in cash an amount equal to the

average closing price of your Vested SPUs based on the last twenty trading days immediately prior to the end of the Performance Period, less any taxes the Company is required to withhold from such payment. Payment will be made as soon as practicable after the end of the Performance Period, but no later than 2½ months following the end of the calendar year in which the Performance Period terminates, less all applicable taxes required to be withheld therefrom, unless deferred into the Executive Deferred Compensation Plan in accordance with Code Section 409A.

(b) DERs. As soon as administratively practicable after the end of the Performance Period (but no later than 2½ months following the end of the Plan year in which the Performance Period terminates), the Company shall pay you in cash, with respect to each SPU that became Vested at the end of the Performance Period, an amount equal to the DERs credited to your DER account during the Performance Period with respect to such Vested SPUs, less any taxes the Company is required to withhold from such payment.

5.Limitations Upon Transfer. All rights under this Award Agreement shall belong to you alone and may not be transferred, assigned, pledged, or hypothecated by you in any way (whether by operation of law or otherwise), other than by will or the laws of descent and distribution or by a beneficiary designation form filed with the Company in accordance with the procedures established by the Company for such designation, and shall not be subject to execution, attachment, or similar process. Upon any attempt by you to transfer, assign, pledge, hypothecate, or otherwise dispose of such rights contrary to the provisions in this Award Agreement or the Plan, or upon the levy of any attachment or similar process upon such rights, such rights shall immediately become null and void.

6.Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successor or successors of the Company and upon any person lawfully claiming under you.

7.Entire Agreement. This Agreement along with the Plan constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the SPUs granted hereby. Without limiting the scope of the preceding sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect.

8.Modifications. Any modification of this Agreement shall be effective only if it is in writing and signed by both you and an authorized officer of the Company.

9.Governing Law. This award shall be governed by, and construed in accordance with, the laws of the State of Colorado, without regard to conflicts of laws or principles thereof.

10.Plan Controls.By accepting this Award, you acknowledge and agree that the SPUs are granted under and governed by the terms and conditions of this Award Agreement and the Plan, a copy of which has been furnished to you. In the event of any conflict between the Plan and this Award Agreement, the terms of the Plan shall control. All decisions or interpretations of the Committee upon any questions relating to the Plan or this Award Agreement are binding, conclusive and final on all persons.

DCP Services, LLC

By:

Name:

Title:

Awardee Acknowledgement and Acceptance

By:

Name:

Performance Schedule

EX-10.2

DCP Midstream, LP

2016 Long-Term Incentive Plan

Form of Restricted Phantom Unit Award Agreement

Awardee:   __________

Award Date:   __________

(also known as Grant Date)

Restricted Period:  __________

1.Award of Restricted Phantom Units (also known as Grant). DCP Services, LLC (the “Company”) hereby grants to you Phantom Units hereafter referred to as Restricted Phantom Units (“RPUs”) allocated as __________DCP common units under the DCP Midstream, LP 2016 Long-Term Incentive Plan (the “Plan”) on the terms and conditions set forth herein. The number of RPUs has been determined based on the average closing price of the DCP common units during the last twenty trading days immediately prior to the Award Date and includes a tandem Dividend Equivalent Right (“DER”) grant with respect to each RPU. The Company will establish a DER bookkeeping account for you with respect to each RPU granted that shall be credited with an amount equal to the cash dividends, expressed in US dollars, made during the Restricted Period with respect to the DCP common units. Unless otherwise defined herein, terms used, but not defined, in this Award Agreement shall have the same meaning as set forth in the Plan.

2.Vesting.The RPUs are considered “Vested” once they are no longer forfeitable.Except as provided in Paragraph 3 below, the RPUs granted hereunder shall become Vested only if you have not ceased to be an Employee for any reason (a “Termination of Service”) prior to the end of the Restricted Period.

3.Early Vesting Events. You may become Vested prior to the end of the Restricted Period as provided in Paragraph (a) below.

(a) Death, Disability, Layoff or Retirement. If you incur a Termination of Service after the first anniversary of your initial Award Date for the year as a result of your death, disability or layoff, the Restricted Period shall terminate and your RPUs and unpaid DERs will become fully Vested on the date of your Termination of Service. If you incur a Termination of Service after the first anniversary of your initial Award Date for the year as a result of your Retirement, the Company may, in its sole discretion, vest (fully or on a pro-rata basis) the RPUs and unpaid DERs and terminate the Restricted Period.

(b) Other Terminations of Service. If your Termination of Service occurs prior to the end of the Restricted Period for any reason other than as provided in Paragraph 3(a) above, the Restricted Period shall terminate and all of your RPUs and unpaid DERs shall be forfeited without payment automatically upon the date of your Termination of Service.

4.Payments.

(a)RPUs. As soon as administratively practicable after the last day of the Restricted Period, you will be issued DCP common units equal to the number of your Vested RPUs, unless the Company decides to pay in cash an amount equal to the average closing price of your Vested RPUs based on the last twenty trading days immediately prior to the end of the Restricted Period, less any taxes the Company is required to withhold from such payment. The Company has sole discretion to determine which method of payment will be used. Payment will be made no later than 2½ months following the end of the calendar year in which the Restricted Period terminates, less all applicable taxes required to be withheld therefrom, unless deferred into the Executive Deferred Compensation Plan in accordance with Code Section 409A.

(b)DERs. As soon as administratively practicable after each quarterly dividend payment date during the Restricted Period, the Company shall pay you in cash, with respect to each RPU, an amount equal to the DERs credited to your DER account during that calendar quarter, less any taxes the Company is required to withhold from such payment.

5.Limitations Upon Transfer. All rights under this Award Agreement shall belong to you alone and may not be transferred, assigned, pledged, or hypothecated by you in any way (whether by operation of law or otherwise), other than by will or the laws of descent and distribution or by a beneficiary designation form filed with the Company in accordance with the procedures established by the Company for such designation, and shall not be subject to execution, attachment, or similar process. Upon any attempt by you to transfer, assign, pledge, hypothecate, or otherwise dispose of such rights contrary to the provisions in this Award Agreement or the Plan, or upon the levy of any attachment or similar process upon such rights, such rights shall immediately become null and void.

6.Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successor or successors of the Company and upon any person lawfully claiming under you.

7.Entire Agreement. This Agreement along with the Plan constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the RPUs granted hereby. Without limiting the scope of the preceding sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect.

8.Modifications. Any modification of this Agreement shall be effective only if it is in writing and signed by both you and an authorized officer of the Company.

9.Governing Law. This award shall be governed by, and construed in accordance with, the laws of the State of Colorado, without regard to conflicts of laws or principles thereof.

10.Plan Controls.By accepting this Award, you acknowledge and agree that the RPUs are granted under and governed by the terms and conditions of this Award Agreement and the Plan, a copy of which has been furnished to you. In the event of any conflict between the Plan and this Award Agreement, the terms of the Plan shall control. All decisions or interpretations of the Committee upon any questions relating to the Plan or this Award Agreement are binding, conclusive and final on all persons.

DCP Services, LLC

By:

Name:

Title:

Awardee Acknowledgement and Acceptance

By:

Name:

EX-10.3

DCP Services, LLC

Executive Severance Plan

and

Summary Plan Description

Table of Contents

INTRODUCTION		1
ARTICLE 1. DEFINITIONS		2
1.1	Active Employee	2
1.2	Administrator	2
1.3	Affiliate	2
1.4	Base Pay	2
1.5	Cause	2
1.6	COBRA	2
1.7	Code	2
1.8	Creditable Leave of Absence	3
1.9	Effective Date	3
1.10	Eligible Employee	3
1.11	Employee	3
1.12	Employer	3
1.13	Employment	3
1.14	Employment Classification(s)	3
1.15	ERISA	4
1.16	Family and Medical Leave	4
1.17	Furlough	4
1.18	Hour of Service	4
1.19	Military Leave	4
1.20	Plan	4
1.21	Plan Sponsor	4
1.22	Plan Year	4
1.23	Release	4
1.24	Service Date	4
1.25	Severance Pay	4
1.26	Sick Leave	4
1.27	STD Leave	4
1.28	Subsidy Period	4
1.29	Termination Date	5
1.30	Weekly Pay	5
1.31	Year of Service	5
ARTICLE 2. ELIGIBILITY		6
2.1	Eligibility Requirements for Severance Pay	6
2.2	Ineligible Terminations	6
ARTICLE 3. SEVERANCE BENEFITS		7

1

3.1	Severance Pay	7
3.2	Timing and Form of Payment	7
3.3	Outplacement Assistance	7
3.4	Subsidized COBRA Coverage	7
ARTICLE 4. CONDITIONS FOR RECEIPT OF SEVERANCE PAY		9
4.1	Execution of Release	9
4.2	Confidentiality and Non-Disclosure Agreement	9
4.3	Additional Conditions	9
4.4	Offset for Money Owed to the Employer	9
4.5	Other Benefits	9
4.6	Payments to Estate	9
4.7	Coordination with Short-Term Incentive Plan	9
4.8	Coordination with Long-Term Incentive Plan	10
4.9	Repayment of Benefit	10
ARTICLE 5. ADMINISTRATION		11
5.1	Administration and Interpretation of the Plan	11
5.2	Information	12
5.3	Fiduciary Provisions	12
5.4	Indemnification	12
5.5	Expenses of Administration	12
5.6	Accounts and Records	12
5.7	Notification of Employees	12
5.8	Claims Procedure	12
ARTICLE 6. GENERAL PROVISIONS		15
6.1	Entire Understanding	15
6.2	Payments from the Plan	15
6.3	Rights Against Employer	15
6.4	Amendment; Termination	15
6.5	Severability	15
6.6	Non-Assignable	15
6.7	Governing Law	15
6.8	Forum and Waiver of Trial by Jury	15
6.9	Code Section 409A	16
RIGHTS OF PLAN PARTICIPANTS		17
GENERAL PLAN INFORMATION		19
SCHEDULE A		A-1

2

SCHEDULE B	B-1
SCHEDULE C	C-1
SCHEDULE D	D-1

3

INTRODUCTION

DCP Services, LLC Executive Severance Plan (the “Plan”) is sponsored by DCP Services, LLC (the “Plan Sponsor”) for the purpose of providing severance benefits to certain employees of the Employer. Participation in the Plan is limited to those Employees who are involuntarily terminated, through no fault of their own, or whose employment is terminated through an Employer-initiated separation as further set forth herein. This Plan does not apply to any other persons, including those who voluntarily terminate employment.

This Plan was originally effective as of January 1, 2015. This amended and restated Plan is effective as of February 19, 2020 (the “Effective Date”), and will remain in effect, unaltered, unless formally amended or terminated in writing by the Plan Sponsor. No employee, supervisor, or manager of the Employer has any authority to alter, amend or make exceptions to this Plan. This Plan is not a contract of employment, and does not entitle any person to any term or length of employment. The Plan is specifically intended to be an unfunded “welfare benefit plan” as that term is defined in the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and is not a pension benefit plan. Only those Employees who actually receive benefits under the terms of the Plan are deemed to be “participants” of the Plan for purposes of the terms provided herein, but any Employees who would be eligible to receive benefits under the terms of the Plan if the payment events were triggered are considered “participants” for purposes of ERISA rights.

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ARTICLE 1.

DEFINITIONS

1.1Active Employee means an Employee who is performing the regular duties of his or her position with the Employer or who is on a Creditable Leave of Absence.

1.2Administrator means the Plan Sponsor unless the Plan Sponsor appoints an administrator in accordance with Section 5.1.

1.3Affiliate means, with respect to any person, any other person that directly or indirectly through one or more intermediaries’ controls, is controlled by or is under common control with, the person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract or otherwise, and includes Enbridge, Inc. (and any successor in interest) so long as it owns a fifty percent (50%) interest in the Plan Sponsor, and also Phillips 66 (and any successor in interest) so long as it owns a fifty percent (50%) interest in the Plan Sponsor.

1.4Base Pay means the annual amount of compensation regularly paid to an Employee, (excluding overtime, bonuses, differentials, allowances, incentive pay, commissions and any other supplemental remuneration to the Employee) as determined on the Termination Date.

1.5Cause means—

(a)the Employee’s willful or repeated refusal to obey written directions of the Employer (so long as such directions do not involve illegal acts);

(b)acts of substance abuse by the Employee that are injurious to the Employer;

(c)fraud or dishonesty by the Employee that is injurious to the Employer;

(d)the Employee being charged with any felony crime (whether in connection with the Employer’s affairs or otherwise);

(e)any misrepresentation by the Employee of a fact, or omission of a material fact, concerning his or her professional qualifications or experience, the termination of any prior employment, or any litigation or proceedings commenced against or by the Employee involving actual or alleged illegal behavior, whether made in the Employee’s resume or in other written materials; or

(f)violation of any Employer policy applicable to Employee.

1.6COBRA means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended, and related regulations.

1.7Code means the Internal Revenue Code of 1986, as amended, and related regulations.

1.8Creditable Leave of Absence means a period of absence from Employment because of Family and Medical Leave, Military Leave, Sick Leave, STD Leave, or Furlough and excludes all other leaves of absence, including personal leaves of absence.

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1.9Effective Date means February 19, 2020.

1.10Eligible Employee means an Employee who—

(a)is employed as an Active Employee on a full-time or part-time basis with an Employment Classification of Director (or equivalent) or higher;

(b)does not have a written employment or termination agreement in effect on the applicable Termination Date that waives participation in the Plan or otherwise provides for severance benefits; and

(c)has satisfied the requirements of Section 2.1.

1.11Employee means any individual who performs services for the Employer and receives compensation for such services other than any individual who—

(a)is classified by the Employer as a temporary employee;

(b)is classified by the Employer as an agent, consultant, independent contractor or self-employed individual regardless of whether such person is later determined to have an employer-employee relationship with the Employer; or

(c)provides services to the Employer under a written contract between the Employer and a temporary help firm, employee leasing agency, technical services firm, outsourcing company, professional employer organization or similar entity, regardless of whether such person is later determined to have an employer-employee relationship with the Employer.

1.12Employer means the Plan Sponsor and its Affiliates other than:

(a)Enbridge, Inc. (and any successor in interest);

(b)Phillips 66 (and any successor in interest); and

(c)Any other entity specifically excluded from participation under the Plan by the Plan Sponsor.

1.13Employment means an individual’s service as an Employee with the Employer that begins on the Employee’s Service Date and ends on the Employee’s Termination Date. Periods during which an Employee is on a Creditable Leave of Absence will be treated as periods of continuous Employment.

1.14Employment Classification(s) means the classification of such Employee determined by the Administrator and as listed in Section 3.1 on such Employee’s Termination Date.

1.15ERISA means the Employee Retirement Income Security Act of 1974, as amended, and related regulations.

1.16Family and Medical Leave means a leave of absence taken pursuant to the Family and Medical Leave Act of 1993, as amended, and related regulations.

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1.17Furlough means paid or unpaid leave taken as required by the Employer due to lack of work.

1.18Hour of Service means each hour for which an Employee is paid or entitled to payment from the Employer for the performance of duties.

1.19Military Leave means leave taken pursuant to the Employer’s military leave policy.

1.20Plan means the DCP Services, LLC Executive Severance Plan.

1.21Plan Sponsor means DCP Services, LLC.

1.22Plan Year means the 12-consecutive-month period beginning each January 1 and ending each December 31.

1.23Release means the separation agreement and general release prepared by and acceptable to the Employer. The Release, in consideration of the benefits provided under the Plan, is intended to legally bind the Employee and the Employer regarding the termination of the Employee’s Employment with the Employer, require repayment of benefits under the Plan under certain rehire circumstances and, among other things, provide for a full release and waiver by the Employee of all possible claims against the Employer and its Affiliates and all directors, officers, employees, agents, and representatives of the Employer and its Affiliates, including, but not limited to, claims arising out of the Employee’s Employment with, and termination of Employment by, the Employer.

1.24Service Date means the base date used by the Employer to determine the Employee’s service anniversary under the service award program, determined in the sole discretion of the Employer.

1.25Severance Pay means the benefit payable to an Eligible Employee under this Plan, calculated under Section 3.1.

1.26Sick Leave means leave taken for which the Employee receives benefits under the sick leave policy of the Employer.

1.27STD Leave means leave taken for which the Employee receives benefits under the short-term disability salary continuation policy of the Employer.

1.28Subsidy Period means, for each Employee, the closest number of whole months that corresponds to the period of Base Pay or Weekly Pay, as applicable, received as Severance Pay under Section 3.1. In determining the closest number of whole months for Severance Pay expressed in Weekly Pay, the number of weeks of Weekly Pay will be converted to months by dividing the total number of weeks of Weekly Pay by four and one-third (4-1/3) and rounding to the closest whole month.

1.29Termination Date means the last date on which an Employee performs an Hour of Service.

1.30Weekly Pay means the amount of the Employee’s Base Pay divided by 52.

1.31Year of Service means a one-year period, beginning on an Employee’s Service Date and each anniversary of such Service Date thereafter, during which period the Employee is engaged in continuous Employment. Fractional or partial Years of Service will be disregarded, and no period of time will count towards more than one Year of Service.

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ARTICLE 2.

ELIGIBILITY

2.1.Eligibility Requirements for Severance Pay. An Eligible Employee becomes a participant under the Plan if such Employee meets each of the following requirements:

(a)the Employee is notified that his or her Employment with the Employer is subsequently terminated, and such Employee is specifically notified that such termination is eligible for Severance Pay if all requirements under this Section 2.1 are satisfied;

(b)the Employee is an Active Employee as of the date of notification and continues to work productively for the Employer, to the extent required, as determined in the sole discretion of the Employer, until the Employer determines that the Employee’s services are no longer necessary;

(c)the Employee’s Termination Date is on or after the Effective Date of this Plan;

(d)the Employee executes a Release, as provided in Section 4.1 within the prescribed period; and

(e)the Employee is not subsequently employed by the Employer or an Affiliate within 30 days following the Employee’s Termination Date.

2.2.Ineligible Terminations. An Employee who is otherwise eligible for any benefits under this Plan will not receive such benefits if the Employee, as determined by the Employer in its absolute discretion —

(a)unilaterally and voluntarily resigns;

(b)is terminated for Cause; or

(c)leaves the Employer’s employment for any reason (including death, disability, disappearance or presumed death) before the requirements of Section 2.1 are satisfied.

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ARTICLE 3.

SEVERANCE BENEFITS

3.1.Severance Pay. An Eligible Employee who complies with the terms of this Plan, becomes a participant in the Plan pursuant to Section 2.1, and signs, delivers, complies with and does not timely revoke the Release will be eligible to receive Severance Pay, less applicable taxes and withholding, in the amount set forth under subparagraphs (a) through (d) below based upon such Employee’s Employment Classification:

(a)Chief Executive Officer. An Eligible Employee with an Employment Classification of Chief Executive Officer will be paid Severance Pay in accordance with Schedule A.

(b)Executive Committee. An Eligible Employee with an Employment Classification of Executive Committee will be paid Severance Pay in accordance with Schedule B.

(c)Vice President. An Eligible Employee with an Employment Classification of Vice President will be paid Severance Pay in accordance with Schedule C.

(d)Director. An Eligible Employee with an Employment Classification of Director will be paid Severance Pay in accordance with Schedule D.

3.2.Timing and Form of Payment. If all conditions for receipt of Severance Pay are satisfied, payment of an Eligible Employee’s Severance Pay will be made in a single cash lump sum payment as soon as administratively feasible following the end of any applicable Release rescission period, providedthat, payment will be made within 74 days of the Employee’s Termination Date. The Employer will withhold any amounts required by the federal, state, or local law.

3.3.Outplacement Assistance. The Employer may, in its discretion, offer an Eligible Employee who satisfies all the conditions for receipt of Severance Pay outplacement counseling assistance selected by the Employer. Such program may vary by Eligible Employee as determined by the Employer. In no event will outplacement services be provided in excess of 12 months to an Eligible Employee. An Eligible Employee may be provided outplacement counseling assistance upon notification of termination of employment, but the provision of such outplacement assistance does not entitle an Eligible Employee to continue such services under this Section 3.3, if such Employee does not satisfy all conditions for receipt of Severance Pay.

3.4.Subsidized COBRA Coverage. If all conditions for receipt of Severance Pay are satisfied and if an Eligible Severance Employee elects continuation coverage under COBRA, the Employer will contribute an amount towards COBRA coverage such that the cost of Employee’s health coverage following the Termination Date will be the same as the cost of such Employee’s health coverage in place immediately prior to the Termination Date. The Employer will provide such amount on a monthly basis until the end of the Subsidy Period or, if earlier, the first to occur of the following: (1) such Employee becomes eligible to receive group health insurance from another employer’s group health plan or spouse’s employer plan, (2) such Employee’s COBRA coverage is terminated for any reason (including by reason of the Employee becoming entitled to Medicare) regardless of whether coverage is continued by a separate qualified beneficiary, or (3) the expiration of the applicable maximum COBRA period for the Employee (generally, the maximum COBRA period is 18 months but in cases of disability may be extended to 29 months). If such Employee is determined by the Employer to be a “highly compensated individual” under

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Code Section 105(h), such contributions by the Employer will be made on an after-tax basis and will be grossed up for applicable tax withholding. The determination of any gross-up required by this Section 3.4 will be calculated and determined in the Employer’s sole discretion. To the extent COBRA coverage premium payments have been made on behalf of an Eligible Employee before all conditions for receipt of Severance Pay have been satisfied and such conditions are not thereafter satisfied, such Employee will reimburse Employer for any amounts paid by Employer for COBRA coverage.

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ARTICLE 4.

CONDITIONS FOR RECEIPT OF SEVERANCE PAY

4.1.Execution of Release. In consideration for and as a pre-condition of receiving Severance Pay and benefits described under Sections 3.1, 3.3, and 3.4, an Employee must execute a Release in a form provided by the Employer. The Release must be voluntarily executed by the Employee, and the Employee must not revoke such Release within any applicable revocation period that may be required by law from time to time. The Release must be executed by the Employee within forty-five (45) days, or such shorter period provided by the Release, following the Employee’s Termination Date.

4.2.Confidentiality and Non-Disclosure Agreement. In consideration for and as a pre-condition of receiving Severance Pay and benefits described under Sections 3.1, 3.3, and 3.4, the Employer may require (either as part of the Release or otherwise) an Employee to execute a confidentiality and non-disclosure agreement in a form approved by the Employer. A confidentiality and non-disclosure agreement, if any, must be voluntarily executed by the Employee within forty-five (45) days, or such shorter period provided by such agreement, following the Employee’s Termination Date. If an Employee executed a similar agreement on the date the Employee was hired or at any time during Employment, by accepting Severance Pay under this Plan, such Employee agrees that the previously executed confidentiality and/or non-disclosure agreement will survive the Employee’s termination of employment with the Employer.

4.3.Additional Conditions. The Employer may also require an Eligible Employee, as conditions precedent to receiving Severance Pay and any other benefits under the Plan, to satisfy any working or scheduling conditions required by the Employer.

4.4.Offset for Money Owed to the Employer. An Employee’s benefit under this Plan will be reduced by any amount that the Employee owes to the Employer on his or her Termination Date, and by accepting and executing the Release, Employee consents to such offset.

4.5.Other Benefits. The benefits of an Employee under any other Employer benefit plan or program are governed solely by the terms of those plans and programs and will neither be affected by nor affect payments under this Plan.

4.6.Payments to Estate. If an Eligible Employee who has become a participant in the Plan pursuant to Section 2.1 dies before receiving the applicable Severance Pay benefit to which he or she is entitled under the Plan, the benefit will be paid to the Employee’s estate. If such Employee has not executed a Release before death, the Employee’s estate will not be entitled to any Severance Pay. Notwithstanding the foregoing, the Employer may, in its discretion, waive conditions for receipt of the benefit, including the requirement for a Release.

4.7.Coordination with Short-Term Incentive Plan. Notwithstanding Section 4.5, if an Eligible Employee has satisfied all conditions for receipt of Severance Pay, a termination of such Employee’s Employment will be considered a qualifying layoff under the DCP Services, LLC Short-Term Incentive Plan (effective January 1, 2012) (“STIP”) and any successor plans (provided such Employee is a participant in such plan as of the Termination Date). Unless provided otherwise in the applicable Release, a pro-rata portion of any payment under the STIP that would otherwise be forfeited due to termination of employment will be paid as a result of a qualifying layoff provided that such payment is otherwise due under the terms of the STIP (e.g., performance goals have been met). Any pro-rata portion payable will be determined by

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multiplying eligible base and overtime pay received in the year by the STIP target and performance factors. Any such pro-rata payment due will be made at the same time and in the same manner as other payments made under the STIP.

4.8.Coordination with Long-Term Incentive Plan. Notwithstanding Section 4.5, if an Eligible Employee has satisfied all conditions for receipt of Severance Pay, a termination of such Employee’s Employment will be considered a layoff (if applicable) under the DCP Midstream, LP 2016 Long-Term Incentive Plan (effective April 28, 2016), the DCP Services, LLC Long-Term Incentive Plan (effective January 1, 2008), the DCP Midstream, LP 2012 Long-Term Incentive Plan (effective February 15, 2012), and any successor plans, or, if applicable, any similar plans (provided such Employee is a participant in such plans as of the Termination Date).

4.9.Repayment of Benefit.

(a)Benefit Calculated by Reference to Weekly Pay. If an Employee received Severance Pay under the Plan calculated by reference to Weekly Pay and is reemployed by the Employer during the period beginning on the Employee’s Termination Date and equaling the number of weeks associated with the number of weeks of Weekly Pay used to calculate such Employee’s Severance Pay, the Employee must repay the portion of Severance Pay relating to the number of full weeks of such period that have not expired as of the date of such Employee’s reemployment. For example, if an Employee has a Termination Date of March 1, is entitled to Severance Pay equal to 10 weeks of Weekly Pay and is reemployed on March 10, then the Employee is required to repay 80% of the Severance Pay received. The terms of such repayment will be set in the Employer’s sole discretion.

(b)Benefit Calculated by Reference to Base Pay.If an Employee received Severance Pay under the Plan calculated by reference to Base Pay and is reemployed by the Employer during the period beginning on the Employee’s Termination Date and equaling the number of months associated with the number of months of Base Pay used to calculate such Employee’s Severance Pay, the Employee must repay the portion of Severance Pay relating to the number of full months of such period that have not expired as of the date of such Employee’s reemployment. For example, if an Employee has a Termination Date of March 1, is entitled to Severance Pay equal to one and one-half (1-1/2) times Base Pay, and is reemployed on November 10, then the Employee is required to repay 50% of the Severance Pay received. The terms of such repayment will be set in the Employer’s sole discretion.

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ARTICLE 5.

ADMINISTRATION

5.1Administration and Interpretation of the Plan. The Plan Sponsor is the Administrator unless the Plan Sponsor appoints an individual or a committee as Administrator in writing. If the Plan Sponsor appoints a committee to serve as the Administrator, the committee must consist of not less than three members. Any member of the committee may resign at any time by giving notice to the Plan Sponsor. Any resignation will take effect at the date of receipt of such notice (or at any later date specified in the notice) and will be deemed to occur upon termination of the member’s employment. No member of the committee may receive any compensation for his or her services as a member of the committee. A majority of the members of the committee will constitute a quorum for the transaction of business. All resolutions or other actions taken by the committee will require the written approval or affirmative vote of a majority of the members of the committee. The Plan Sponsor is entitled to remove the Administrator or committee member at any time, with or without cause. The Administrator has all powers necessary or convenient to administer the Plan, including, in addition to such other powers as the law may provide, the following:

(a)all powers to administer the Plan, within its discretion, including but not limited to the power to establish rules and procedures for the purpose of administration of this Plan;

(b)total and complete discretion to interpret the Plan and to determine all questions arising in the administration, interpretation and application of the Plan, including the power to construe and interpret the Plan; to decide all questions relating to an individual’s eligibility for benefits and the amounts thereof; to make such adjustments which it deems necessary or desirable to correct any arithmetical or accounting errors; to determine the amount, form and timing of any distribution to be made hereunder;

(c)to increase the amount of benefits that would otherwise be provided under the Plan as it deems desirable and to subject such additional benefit to the requirements and conditions described herein;

(d)to correct any defect, supply any omission or reconcile any inconsistency in such manner and to such extent as the Administrator deems necessary to carry out the purposes of this Plan;

(e)exclusive fact finder discretionary authority to decide all facts relevant to the determination of eligibility for benefits; discretion to make factual determinations as well as decisions and determinations relating to the amount and manner of the distribution of benefits; and in making such decisions, be entitled to, but need not rely upon, information supplied by an Employee or representative thereof; and

(f)the power to appoint such agents, attorneys, accountants, and consultants and any other person required for proper administration of the Plan.

The decisions of the Administrator are conclusive and binding upon all persons having or claiming to have any right or interest in or under the Plan, and no such decision may be modified under judicial review unless such decision is proven to be arbitrary or capricious.

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5.2Information. The Administrator may require that each Employee supply any information and execute any documents necessary under this Plan.

5.3Fiduciary Provisions. The Administrator is a “named fiduciary” under the Plan. Any person or group of persons may serve in more than one fiduciary capacity with respect to the Plan. All fiduciaries under the Plan must discharge their duties with respect to the Plan solely in the interests of the Employees and their beneficiaries and with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of alike character and with like aims. No fiduciary under the Plan will be liable for an act or omission of another person in carrying out any fiduciary responsibility where such fiduciary responsibility is allocated to such other person by or pursuant to the Plan.

5.4Indemnification. The Employer will, to the fullest extent permitted by law, indemnify each director, officer, or employee of the Employer (including the heirs, executors, administrators, and other personal representatives of such person) and the Administrator against expenses (including attorneys’ fees), judgments, fines, and amounts paid in settlement actually and reasonably incurred by a person covered under this indemnification clause in connection with any threatened, pending, or actual suit, action, or proceeding (whether civil, criminal, administrative, or investigative in nature, or otherwise) in which the person may be involved by reason of the fact that the person is or was serving the Plan in any capacity at the request of the Employer.

5.5Expenses of Administration. Any expense incurred by the Employer or the Administrator relative to the administration of the Plan will be paid by the Employer.

5.6Accounts and Records. The Administrator will maintain records concerning the eligibility of Employees and itemize and separately identify the benefits distributed under the Plan.

5.7Notification of Employees. The Administrator will communicate in writing to all Employees (whom could become a participant under the Plan pursuant to Section 2.1) a summary of the terms and conditions of the Plan, which in the Administrator’s discretion, may be a copy of the Plan.

5.8Claims Procedure.

(a)Filing a Claim for Benefits. If an Employee or former Employee believes that the Employer is obligated under the terms of the Plan to pay a benefit, the Employee or former Employee (hereinafter referred to as the “claimant”) must deliver a written request to the Administrator, or such person or office as the Administrator designates for the processing of claims. Upon receipt of such request, the Administrator may require the claimant to complete such forms and provide such additional information as may be reasonably necessary to establish the claimant’s right to benefits under the Plan. A claim is deemed filed upon receipt by the Administrator.

(b)Notification to Claimant of Decision. The Administrator will furnish to the claimant a notice of the decision within 90 days after receipt of the claim. If special circumstances require more than 90 days to process the claim, this period may be extended for up to an additional 90 days by giving written notice to the claimant before the end of the initial 90-day period stating the special circumstances requiring the extension and the date by which a final decision is expected. Failure to provide a notice of decision within the time

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specified will constitute a denial of the claim, and the claimant will be entitled to require a review of the denial under the review procedures.

The notice to be provided to every claimant who is denied a claim for benefits must be in writing and must set forth, in a manner calculated to be understood by the claimant, the following:

(1)the specific reason or reasons for the denial;

(2)specific reference to pertinent Plan provisions on which the denial is based;

(3)a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and

(4)an explanation of the Plan’s claims review procedure describing the steps to be taken by a claimant who wishes to submit his or her claim for review, including a statement of the claimant’s right to bring a civil action pursuant to ERISA Section 502.

(c)Review Procedure. The purpose of the review procedure is to provide a procedure by which an Employee or former Employee claiming benefits may have a reasonable opportunity to appeal a denial of a claim to the Administrator for a full and fair review as required by ERISA Section 503. To accomplish that purpose, the claimant or his or her duly authorized representative may request a review upon written application to the Administrator, review pertinent Plan documents and submit issues and comments in writing. A claimant (or his or her duly authorized representative) must request a review by filing a written application for review with the Administrator at any time within 60 days after receipt by the claimant of written notice of the denial of his or her claim.

The decision on review will be made by the Administrator, who may in his, her, or its discretion hold a hearing on the denied claim. The Administrator will make its decision promptly, which will ordinarily be not later than 60 days after the Plan’s receipt of the request for review, unless special circumstances (such as the need to hold a hearing) require an extension of time for processing. In that case a decision will be rendered as soon as possible, but not later than 120 days after receipt of the request for review. If an extension of time is required due to special circumstances, written notice of the extension will be furnished to the claimant prior to the time the extension commences. The decision on review must be in writing and must include specific reasons for the decision (written in a manner calculated to be understood by the claimant), as well as specific references to the pertinent Plan provisions on which the decision is based.

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ARTICLE 6.

GENERAL PROVISIONS

6.1Entire Understanding. This Plan constitutes the entire commitment of the Employer with respect to Eligible Employees and the matters set forth in this Plan and supersedes any and all separation or severance plans and programs with respect to such Employees which may have been maintained previously by the Employer. Further, the Plan supersedes any and all negotiations, representations, warranties or agreements between the Employer and such Employees, unless an Employee has an employment agreement with the Employer governing the terms of such Employee’s termination of employment that is in effect on the date of his or her termination.

6.2Payments from the Plan. Payments from the Plan will be paid out of the general assets of the Employer at the time payments are required. The Employer is not required to set aside amounts in advance of the date payments are required.

6.3Rights Against Employer. Neither the establishment of the Plan, nor any modification of the Plan, nor any distributions from the Plan may be construed as giving to any current or former Employee or beneficiary any legal or equitable rights against the Employer, its shareholders, directors, or officers, as such, or as giving any person the right to be retained in the employ of the Employer.

6.4Amendment; Termination. The Plan Sponsor reserves the right to amend, modify or terminate this Plan at any time for any reason, which may result in the termination or modification of coverage or benefits under this Plan. Any such amendment or termination must be set forth in writing.

6.5Severability. A determination that any provision of this Plan is prohibited by law or unenforceable will not affect the validity or enforceability of any other provision of this Plan.

6.6Non-Assignable. Benefits payable under this Plan are not subject to the claims of any creditor of any Employee. Except as provided in Section 4.6, an Eligible Employee has no rights under this Plan to alienate, pledge, encumber or assign any benefit to which such Employee may become entitled.

6.7Governing Law. To the extent not pre-empted by federal law, this Plan will be governed in all respects by the laws of the State of Colorado without giving effect to its conflicts or choice of law rules.

6.8Forum and Waiver of Trial by Jury. Any legal suit, action or proceeding arising out of or relating to this Plan shall be instituted in the federal courts of the United States of America or the courts of the State of Colorado in each case located in the City of Denver and County of Denver, and each party irrevocably submits to the exclusive jurisdiction of such courts in any such suit, action or proceeding. The parties irrevocably and unconditionally waive any objection to the laying of venue of any suit, action or proceeding in such courts and irrevocably waive and agree not to plead or claim in any such court that any such suit, action or proceeding brought in any such court has been brought in an inconvenient forum. Each party acknowledges and agrees that any controversy which may arise out of or relate to this Plan is likely to involve complicated and difficult issues and, therefore, each such party irrevocably and unconditionally waives any right it may have to a trial by jury in respect of any legal action arising out of or relating to this Plan.

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6.9Code Section 409A. All benefits provided under this Plan are intended to be exempt from Code Section 409A; however, to the extent Code Section 409A applies, the Plan will be interpreted to comply to the maximum extent permitted. Notwithstanding, the Plan Sponsor makes no representation that this Plan complies with Code Section 409A and has no liability to Participants for any failure to comply with Code Section 409A. For purposes of Code Section 409A, all benefits hereunder are designated as separate payments.

* * *

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Rights of Plan Participants

ERISA provides that all plan participants will be entitled to the following:

Receive Information About Your Plan and Benefits.

•Examine, without charge, at the Plan Administrator’s office and at other specified locations, such as worksites, all Plan documents governing the Plan and a copy of the latest annual report (Form 5500 Series) if required to be filed by the Plan with the U.S. Department of Labor (available at the Public Disclosure Room of the Employee Benefit Security Administration).

•Obtain, upon written request to the Plan Administrator, copies of documents governing the operation of the Plan and copies of the latest annual report (Form 5500 Series) and an updated summary plan description. The Plan Administrator may make a reasonable charge for the copies.

•Receive automatically, claims procedures, to the extent such procedures are changed after distribution of this Plan document.

Prudent Actions by Plan Fiduciaries. In addition to creating rights for Plan participants, ERISA imposes duties upon the people who are responsible for the operation of the employee benefit plan. The people who operate the Plan, called “fiduciaries” of the Plan, have a duty to do so prudently and in the interest of you and other plan participants and beneficiaries. No one, including the Employer, may fire you or otherwise discriminate against you in any way to prevent you from obtaining a welfare benefit or exercising your rights under ERISA.

Enforce Your Rights. If your claim for a benefit under this Plan is denied or ignored, in whole or in part, you have the right to know why this was done, to obtain copies of documents relating to the decision without charge, and to appeal any denial, all within certain time schedules. Under ERISA, there are steps you can take to enforce the above rights. For instance, if you request a copy of Plan documents and do not receive them within 30 days, you may file suit in a federal court. In such a case, the court may require the Plan Administrator to provide the materials and pay you up to $110 a day until you receive the materials, unless the materials were not sent because of reasons beyond the control of the Plan Administrator. If it should happen that you are discriminated against for asserting your rights, you may seek assistance from the U.S. Department of Labor, or you may file suit in a federal court. The court will decide who should pay court costs and legal fees. If you are successful, the court may order the person sued to pay these costs and fees. If you lose, the court may order you to pay these costs and fees, for example, if it finds the claim is frivolous.

Assistance with Your Questions. If you have any questions about the Plan, you should contact the Plan Administrator. If you have any questions about this statement or about your rights under ERISA, or if you need assistance in obtaining documents from the Plan Administrator, you should contact the nearest office of the Employee Benefit Security Administration, U.S. Department of Labor, listed in the telephone directory or the Division of Technical Assistance and Inquiries, Employee Benefit Security Administration, U.S. Department of Labor, 200 Constitution Avenue N.W., Washington, D.C. 20210. You may also obtain certain publications about rights and responsibilities under ERISA by calling the publications hotline of the Employee Benefit Security Administration.

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Adopted effective as of February 19, 2020.

DCP SERVICES, LLC

Plan Sponsor

By:	/s/ Brent Backes
Title:	Group Vice President and General Counsel
Date:	February 19, 2020

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General Plan Information

Employer and Plan Sponsor	DCP Services, LLC Attn: Group Vice President and Chief Human Resources Officer Plan Sponsor, Severance Plan 370 17th Street, Suite 2500 Denver, Colorado 80202 (303) 605-1844
Plan Sponsor’s Employer Identification Number (“EIN”)	30-0870571
Plan Name	DCP Services, LLC Executive Severance Plan is a component program under the DCP Services, LLC Welfare Plan
Plan Identification Number	506
Plan Structure	The Plan is an unfunded welfare benefit plan providing severance benefits.
Type of Funding	Benefits are paid from the general assets of the Employer.
Plan Year	January 1 – December 31
Plan Administrator	DCP Services, LLC Attn: Group Vice President and Chief Human Resources Officer Plan Administrator, Severance Plan 370 17th Street, Suite 2500 Denver, Colorado 80202 (303) 605-1844
THE PLAN ADMINISTRATOR IS RESPONSIBLE FOR PROVIDING YOU WITH INFORMATION REGARDING YOUR RIGHTS AND BENEFITS UNDER THE PLAN, FILING VARIOUS REPORTS AND FORMS WITH THE DEPARTMENT OF LABOR AND THE INTERNAL REVENUE SERVICE AND MAKING ALL DISCRETIONARY DETERMINATIONS UNDER THE PLAN.
Agent for Service of Legal Process	DCP Services, LLC Attn: General Counsel Agent for Service of Legal Process, Severance Plan 370 17th Street, Suite 2500 Denver, Colorado 80202 (303) 605-1730

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SCHEDULE A

Severance Pay for Chief Executive Officer

The Chief Executive Officer (“CEO”) is eligible for Severance Pay in an amount equal to two (2) times Base Pay. Additionally, any payment due to the CEO under the STIP and Section 4.7 will not be reduced in a pro-rata manner as described under Section 4.7.

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Schedule A          2/19/2020 A- 1

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SCHEDULE B

Severance Pay for Executive Committee

A member of the Executive Committee is eligible for Severance Pay in an amount equal to one and one-half (1.5) times Base Pay. Additionally, any pro-rata payment due under the STIP and Section 4.7 that would be reduced in the pro-rata manner described under Section 4.7 to below one-half of the amount otherwise payable under the STIP will instead be reduced to one-half of the amount otherwise payable under the STIP.

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SCHEDULE C

Severance Pay for Vice Presidents

A Vice President is eligible for Severance Pay in an amount equal to one (1) times Base Pay.

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SCHEDULE D

Severance Pay for Directors

A Director is eligible for Severance Pay in an amount equal to eight weeks of Weekly Pay plus an additional two weeks of Weekly Pay for each Year of Service completed by such Employee; however, the total number of weeks of Weekly Pay under this calculation will not exceed 39 weeks.

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EX-22

Exhibit 22

List of Guaranteed Securities

Pursuant to Item 601(b)(22) of Regulation S-K, set forth below are securities issued by DCP Midstream Operating, LP (Subsidiary Issuer) and guaranteed by DCP Midstream, LP (Parent Guarantor).

$500 million of 4.750% Senior Notes due September 2021

$350 million of 4.950% Senior Notes due April 2022

$500 million of 3.875% Senior Notes due March 2023

$825 million of 5.375% Senior Notes due July 2025

$600 million of 5.125% Senior Notes due May 2029

$300 million of 8.125% Senior Notes due August 2030

$300 million of 6.450% Senior Notes due November 2036

$450 million of 6.750% Senior Notes due September 2037

$400 million of 5.600% Senior Notes due April 2044

EX-31.1

Exhibit 31.1

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Wouter T. van Kempen, certify that:

1.I have reviewed this quarterly report on Form 10-Q of DCP Midstream, LP for the period ended March 31, 2020;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2020

/s/ Wouter T. van Kempen

Wouter T. van Kempen

President and Chief Executive Officer

(Principal Executive Officer)

DCP Midstream GP, LLC, general partner of
DCP Midstream GP, LP, general partner of
DCP Midstream, LP

EX-31.2

Exhibit 31.2

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Sean P. O'Brien, certify that:

1.I have reviewed this quarterly report on Form 10-Q of DCP Midstream, LP for the period ended March 31, 2020;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2020

/s/ Sean P. O'Brien

Sean P. O'Brien

Group Vice President and Chief Financial Officer

(Principal Financial Officer)

DCP Midstream GP, LLC, general partner of
DCP Midstream GP, LP, general partner of
DCP Midstream, LP

EX-32.1

Exhibit 32.1

Certification of President and Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906

of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

The undersigned, the President and Chief Executive Officer of DCP Midstream GP, LLC, general partner of DCP Midstream GP, LP, general partner of DCP Midstream, LP (the “Partnership”), hereby certifies that, to his knowledge on the date hereof:

(a)the quarterly report on Form 10-Q of the Partnership for the period ended March 31, 2020, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Wouter T. van Kempen

Wouter T. van Kempen

President and Chief Executive Officer

(Principal Executive Officer)

May 7, 2020

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of Group Vice President and Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906

of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

The undersigned, the Group Vice President and Chief Financial Officer of DCP Midstream GP, LLC, general partner of DCP Midstream GP, LP, general partner of DCP Midstream, LP (the “Partnership”), hereby certifies that, to his knowledge on the date hereof:

(a)the quarterly report on Form 10-Q of the Partnership for the period ended March 31, 2020, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ Sean P. O'Brien

Sean P. O'Brien

Group Vice President and Chief Financial Officer

(Principal Financial Officer)

May 7, 2020

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

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Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	3 Months Ended
	Mar. 31, 2020 MMBTU bbl	Mar. 31, 2019 MMBTU bbl
Crude Oil
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One | bbl	(1,410,000)	(1,191,000)
Net (Short) Position (Bbls), Year Two | bbl	(1,467,000)	(283,000)
Net (Short) Position (Bbls), Year Three | bbl	(107,000)	(100,000)
Net (Short) Position (Bbls), Year Four | bbl	0	0
Net Long (Short) Position (Bbls), Year Five | bbl	0
Natural Gas [Member]
Net Long (Short) Position, MMBtu [Abstract]
Net (Short) Long Position (MMBtu), Year One | MMBTU	(27,659,800)	(32,148,650)
Net (Short) Long Position (MMBtu), Year Two | MMBTU	(45,540,000)	(930,000)
Net Long Position (MMBtu), Year Three | MMBTU	(13,687,500)	0
Net Long Position (MMBtu), Year Four | MMBTU	0	0
Net Long Position (MMBtu), Year Five | MMBTU	0
Natural Gas Liquids
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One | bbl	(25,009,803)	(26,987,090)
Net (Short) Position (Bbls), Year Two | bbl	(7,294,133)	(14,388,830)
Net (Short) Position (Bbls), Year Three | bbl	(104,842)	(5,516,168)
Net (Short) Position (Bbls), Year Four | bbl	0	(175)
Net Long (Short) Position (Bbls), Year Five | bbl	0
Natural Gas Basis Swaps
Net Long (Short) Position, MMBtu [Abstract]
Net (Short) Long Position (MMBtu), Year One | MMBTU	8,190,000	2,102,500
Net (Short) Long Position (MMBtu), Year Two | MMBTU	4,325,000	3,660,000
Net Long Position (MMBtu), Year Three | MMBTU	8,212,500	(3,650,000)
Net Long Position (MMBtu), Year Four | MMBTU	7,300,000	0
Net Long Position (MMBtu), Year Five | MMBTU	2,140,000

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Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity derivatives - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Offsetting Assets [Line Items]
Gross Amounts of Assets Presented in the Balance Sheet	$ 305	$ 34
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	0
Net Amount	305	34
Offsetting Liabilities [Line Items]
Gross Amounts of Liabilities Presented in the Balance Sheet	(238)	(78)
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	0
Net Amount	$ (238)	$ (78)

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Business Segments - Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Segment Reporting Information [Line Items]
Total operating revenues	$ 1,657	$ 2,199
Gross margin	511	395
Operating and maintenance expense	(153)	(178)
Depreciation and amortization expense	(99)	(103)
General and administrative expense	(56)	(67)
Asset Impairments	(746)	0
Other expense, net	(3)	(5)
Loss on sale of assets, net	0	(9)
Earnings from unconsolidated affiliates	76	113
Interest expense, net	(78)	(69)
Income tax expense	1	1
Net income	(549)	76
Net income attributable to noncontrolling interests	(1)	(1)
Net income attributable to partners	(550)	75
Non-cash derivative mark-to-market	134	(54)
Non-cash lower of cost or net realizable value adjustment	(4)	(5)
Capital expenditures	69	182
Investments in unconsolidated affiliates, net	34	131
Logistics and Marketing
Segment Reporting Information [Line Items]
Total operating revenues	1,358	2,045
Gathering and Processing
Segment Reporting Information [Line Items]
Total operating revenues	913	1,288
Operating Segments | Logistics and Marketing
Segment Reporting Information [Line Items]
Total operating revenues	1,358	1,288
Gross margin	111	337
Operating and maintenance expense	(7)	(165)
Depreciation and amortization expense	(3)	(93)
General and administrative expense	(2)	(6)
Asset Impairments	0
Other expense, net	0	(5)
Loss on sale of assets, net		(9)
Earnings from unconsolidated affiliates	137	0
Interest expense, net	0	0
Income tax expense	0	0
Net income	236	147
Net income attributable to noncontrolling interests	0	(1)
Net income attributable to partners	236	147
Non-cash derivative mark-to-market	42	(36)
Non-cash lower of cost or net realizable value adjustment	(4)	(5)
Capital expenditures	1	165
Investments in unconsolidated affiliates, net	34	0
Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total operating revenues	913	2,045
Gross margin	400	58
Operating and maintenance expense	(142)	(9)
Depreciation and amortization expense	(89)	(3)
General and administrative expense	(3)	(3)
Asset Impairments	(746)
Other expense, net	(3)	0
Loss on sale of assets, net		0
Earnings from unconsolidated affiliates	(61)	113
Interest expense, net	0	0
Income tax expense	0	0
Net income	(644)	68
Net income attributable to noncontrolling interests	(1)	0
Net income attributable to partners	(645)	67
Non-cash derivative mark-to-market	92	(18)
Non-cash lower of cost or net realizable value adjustment	0	0
Capital expenditures	67	14
Investments in unconsolidated affiliates, net	0	131
Other
Segment Reporting Information [Line Items]
Total operating revenues	0	0
Gross margin	0	0
Operating and maintenance expense	(4)	(4)
Depreciation and amortization expense	(7)	(7)
General and administrative expense	(51)	(58)
Asset Impairments	0
Other expense, net	0	0
Loss on sale of assets, net		0
Earnings from unconsolidated affiliates	0	0
Interest expense, net	(78)	(69)
Income tax expense	1	1
Net income	(141)	(139)
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	(141)	(139)
Non-cash derivative mark-to-market	0	0
Non-cash lower of cost or net realizable value adjustment	0	0
Capital expenditures	1	3
Investments in unconsolidated affiliates, net	0	0
Eliminations
Segment Reporting Information [Line Items]
Total operating revenues	(614)	(1,134)
Gross margin	0	0
Operating and maintenance expense		0
Depreciation and amortization expense	0	0
General and administrative expense	0	0
Other expense, net		0
Earnings from unconsolidated affiliates	0	0
Interest expense, net	0	0
Income tax expense	0	0
Net income	0	0
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	0	0
Non-cash derivative mark-to-market		0
Non-cash lower of cost or net realizable value adjustment	0	0
Capital expenditures	0	0
Investments in unconsolidated affiliates, net	$ 0	$ 0

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Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions																3 Months Ended
	Mar. 16, 2020	Feb. 14, 2020	Jan. 15, 2020	Dec. 16, 2019	Nov. 14, 2019	Oct. 15, 2019	Sep. 16, 2019	Aug. 14, 2019	Jul. 15, 2019	Jun. 17, 2019	May 15, 2019	Apr. 15, 2019	Mar. 15, 2019	Feb. 14, 2019	Jan. 15, 2019	Mar. 31, 2020	Mar. 31, 2019
Distribution Made to Limited Partner [Line Items]
Total Cash Distribution																$ 167	$ 159
Series A Preferred Limited Partners [Member]
Distribution Made to Limited Partner [Line Items]
Preferred Limited Partnership Distribution; Distribution Amount Paid				$ 36.875						$ 36.875
Total Cash Distribution				$ 19						$ 18						0	0
Series B Preferred Limited Partners [Member]
Distribution Made to Limited Partner [Line Items]
Preferred Limited Partnership Distribution; Distribution Amount Paid	$ 0.4922			$ 0.4922			$ 0.4922			$ 0.4922			$ 0.4922
Total Cash Distribution	$ 3			$ 4			$ 3			$ 3			$ 3			3	3
Series C Preferred Limited Partners [Member]
Distribution Made to Limited Partner [Line Items]
Preferred Limited Partnership Distribution; Distribution Amount Paid			$ 0.4969			$ 0.4969			$ 0.4969			$ 0.4969			$ 0.5576
Total Cash Distribution			$ 2			$ 2			$ 3			$ 2			$ 2	2	2
Limited Partners
Distribution Made to Limited Partner [Line Items]
Per Unit Distribution (in dollars per share)		$ 0.78			$ 0.78			$ 0.78			$ 0.78			$ 0.78
Total Cash Distribution		$ 162			$ 155			$ 154			$ 155			$ 154		$ 162	$ 111

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Debt - Schedule of Debt (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Facility [Line Items]
Fair value adjustments related to interest rate swap fair value hedges	$ 19	$ 19
Unamortized issuance costs	(36)	(37)
Unamortized discount	(8)	(8)
Finance Lease, Liability	24	25
Total debt	5,924	5,924
Finance Lease, Liability, Current	3	3
Current debt	0	600
Long-term debt	5,921	5,321
Credit Agreement
Facility [Line Items]
Credit Facility	$ 800	200
Weighted-average variable interest rate	2.157%
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,400
Accounts Receivable Securitization Facility
Facility [Line Items]
Accounts Receivable Securitization Agreement	$ 350	350
Weighted-average variable interest rate	1.88%
Line of Credit Facility, Maximum Borrowing Capacity	$ 350
Accounts Recievable included in the Securitization Transaction	590
Senior Notes | Issued March 2010, interest at 5.350% payable semiannually, due March 2020
Facility [Line Items]
Senior Notes	$ 0	600
Debt interest rate percentage	5.35%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 0	600
Senior Notes | Issued September 2011, interest at 4.750% payable semiannually, due September 2021
Facility [Line Items]
Senior Notes	$ 500	500
Debt interest rate percentage	4.75%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 500	500
Senior Notes | Issued March 2012, interest at 4.950% payable semi-annually, due April 2022
Facility [Line Items]
Senior Notes	$ 350	350
Debt interest rate percentage	4.95%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 350	350
Senior Notes | Issued March 2013, interest at 3.875% payable semi-annually, due March 2023
Facility [Line Items]
Senior Notes	$ 500	500
Debt interest rate percentage	3.875%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 500	500
Senior Notes | Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025
Facility [Line Items]
Senior Notes	$ 825	825
Debt interest rate percentage	5.375%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 825	825
Senior Notes | Issued May 2019, interest at 5.125% payable semiannually, due May 2029
Facility [Line Items]
Senior Notes	$ 600	600
Debt interest rate percentage	5.125%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 600	600
Senior Notes | Issued August 2000, interest at 8.125% payable semi-annually, due August 2030
Facility [Line Items]
Senior Notes	$ 300	300
Debt interest rate percentage	8.125%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 300	300
Senior Notes | Issued October 2006, interest at 6.450% payable semi-annually, due November 2036
Facility [Line Items]
Senior Notes	$ 300	300
Debt interest rate percentage	6.45%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 300	300
Senior Notes | Issued September 2007, interest at 6.750% payable semi-annually, due September 2037
Facility [Line Items]
Senior Notes	$ 450	450
Debt interest rate percentage	6.75%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 450	450
Senior Notes | Issued March 2014, interest at 5.600% payable semi-annually, due April 2044
Facility [Line Items]
Senior Notes	$ 400	400
Debt interest rate percentage	5.60%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 400	400
Junior subordinated notes | Issued May 2013, interest at 5.850% payable semi-annually, due May 2043
Facility [Line Items]
Senior Notes	$ 550	550
Debt interest rate percentage	5.85%
Debt Instrument, Interest Rate, Stated Percentage [Abstract]
Debt Instrument, Face Amount	$ 550	$ 550

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Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
Interest capitalized on construction projects	$ 2	$ 5
Depreciation expense	$ 97	$ 101

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Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	$ 76	$ 113
DCP Sand Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	78	68
DCP Southern Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	20	23
Front Range Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	11	7
Gulf Coast Express [Member]
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	16	0
Texas Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	4	5
Mont Belvieu Enterprise Fractionator
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	3	4
Mont Belvieu 1 Fractionator
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	3	4
Discovery Producer Services LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	(61)	0
Other
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	$ 2	$ 2

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Investments in Unconsolidated Affiliates (Tables)

3 Months Ended

Mar. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	March 31, 2020		December 31, 2019
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,768	$	1,764
DCP Southern Hills Pipeline, LLC	66.67%	742		738
Front Range Pipeline LLC	33.33%	209		206
Gulf Coast Express LLC	25.00%	445		449
Texas Express Pipeline LLC	10.00%	100		101
Cheyenne Connector	50.00%	100		83
Mont Belvieu Enterprise Fractionator	12.50%	27		27
Mont Belvieu 1 Fractionator	20.00%	8		9
Discovery Producer Services LLC	40.00%	256		322
Panola Pipeline Company, LLC	15.00%	22		22
Other	Various	4		3
Total investments in unconsolidated affiliates		$	3,681	$	3,724

Schedule Of Earnings From Investment In Unconsolidated Affiliates [Table Text Block]

:

	Three Months Ended March 31,
	2020		2019
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	68
DCP Southern Hills Pipeline, LLC	20		23
Front Range Pipeline LLC	11		7
Gulf Coast Express LLC	16		—
Texas Express Pipeline LLC	4		5
Mont Belvieu Enterprise Fractionator	3		4
Mont Belvieu 1 Fractionator	3		4
Discovery Producer Services LLC (a)	(61)		—
Other	2		2
Total earnings from unconsolidated affiliates	$	76	$	113

Equity Method Investment Summarized Financial Information, Statement of Operations [Table Text Block]

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

	Three Months Ended March 31,
	2020		2019
	(millions)
Statements of operations:
Operating revenue	$	527	$	421
Operating expenses	$	185	$	191
Net income	$	341	$	231

Equity Method Investment Summarized Financial Information Balance Sheet Table [Table Text Block]

	March 31, 2020		December 31, 2019
	(millions)
Balance sheets:
Current assets	$	368	$	463
Long-term assets	7,598		7,546
Current liabilities	(169)		(231)
Long-term liabilities	(257)		(252)
Net assets	$	7,540	$	7,526

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Agreements and Transactions with Affiliates (Tables)

3 Months Ended

Mar. 31, 2020

Related Party Transaction [Line Items]

Schedule of Fees Incurred and Other Fees Paid

The following table summarizes employee related costs that were charged by DCP Midstream, LLC to the Partnership that are included in the condensed consolidated statements of operations:

		Three Months Ended March 31,
		2020		2019
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense		$	44	$	49
General and administrative expense		$	35	$	47

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Three Months Ended March 31,
	2020		2019
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	212	$	326
Purchases and related costs from affiliates	$	27	$	31
Transportation and related costs from affiliates	$	23	$	14
Operating and maintenance and general administrative expenses	$	4	$	4
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	1	$	—
Purchases and related costs from affiliates	$	—	$	7
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	9	$	14
Transportation, processing, and other to affiliates	$	3	$	1
Purchases and related costs from affiliates	$	9	$	24
Transportation and related costs from affiliates	$	215	$	195

 We had balances with affiliates as follows:

	March 31, 2020		December 31, 2019
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	81	$	117
Accounts payable	$	27	$	20
Enbridge (including its affiliates):
Accounts payable	$	—	$	2
Unconsolidated affiliates:
Accounts receivable	$	17	$	21
Accounts payable	$	70	$	78

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Contract Liabilities (Notes)

3 Months Ended

Mar. 31, 2020

Contract Assets and Liabilities [Abstract]

Contract Assets and Liabilities [Text Block]

. Contract LiabilitiesOur contract liabilities consist of deferred revenue received from reimbursable projects. The noncurrent portion of deferred revenue is included in other long-term liabilities on our condensed consolidated balance sheets.

The following table summarizes changes in contract liabilities included in our condensed consolidated balance sheets:

	March 31,
	2020
	(millions)
Balance, beginning of period	$	33
Additions	2
Revenue recognized (a)	(1)
Balance, end of period	$	34

(a) Deferred revenue recognized is included in transportation, processing and other on the condensed consolidated statement of operations.

The contract liabilities disclosed in the table above will be recognized as revenue as the obligations are satisfied over their average remaining contract life, which is 35 years as of March 31, 2020.

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Goodwill and Intangible Assets (Notes)

3 Months Ended

Mar. 31, 2020

Goodwill Disclosure [Abstract]

Goodwill Disclosure [Text Block]

Goodwill

We perform our annual goodwill assessment during the third quarter at the reporting unit level, and update the test during interim periods when we believe events or changes in circumstances indicate that it is more likely than not that an impairment exists. During the first quarter of 2020, certain areas of our business, as well as those of other midstream companies in our peer group, suffered a significant decline in market value. This indicated both a reduction of estimated enterprise value and an increase to our estimated discount rate. Our goodwill impairment assessment is conducted by assessing whether (i) the components of our operating segments constitute businesses for which discrete financial information is available, (ii) segment management regularly reviews the operating results of those components and (iii) the economic and regulatory characteristics are similar. As a result of the increase in our estimated discount rate coupled with a decline in forecasted cash flows due to commodity pricing, we concluded the carrying value of goodwill in the North reporting unit within our Gathering and Processing segment was more likely than not impaired. Therefore, we performed an analysis to determine the estimated fair value of the North reporting unit as of March 31, 2020 and concluded that its carrying value exceeded its fair value by more than the recorded amount of goodwill within the reporting unit, resulting in an impairment charge of $159 million.

The significant decline in commodity prices and demand have decreased forecasted cash flows such that, while in excess of asset book value on an undiscounted basis, they were not sufficient to recover the value of allocated goodwill in the North reporting unit.

We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform our goodwill assessment. Key assumptions in the analysis include the use of an appropriate discount rate, a terminal year multiple, 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. To estimate the discount rate, we used a capital asset pricing model to calculate a rate believed to be consistent with those utilized by market participants.

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

	As of March 31, 2020						As of March 31, 2019
	Gathering and Processing		Logistics and Marketing		Total		Gathering and Processing		Logistics and Marketing		Total
	(millions)
Balance, beginning of period	$	159	$	—	$	159	$	159	$	72	$	231
Impairment	(159)		—		(159)		—		—		—
Dispositions	—		—		—		—		(37)		(37)
Balance, end of period	$	—	$	—	$	—	$	159	$	35	$	194

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

	March 31,		December 31,
	2020		2019
	(millions)
Gross carrying amount	$	145	$	145
Accumulated amortization	(86)		(84)
Accumulated impairment	(11)		—
Intangible assets, net	$	48	$	61

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Debt (Notes)

3 Months Ended

Mar. 31, 2020

Debt Disclosure [Abstract]

Debt

Debt

	March 31, 2020		December 31, 2019
	(millions)
Senior notes:
Issued March 2010, interest at 5.350% payable semi-annually, due March 2020 (a)	$	—	$	600
Issued September 2011, interest at 4.750% payable semi-annually, due September 2021	500		500
Issued March 2012, interest at 4.950% payable semi-annually, due April 2022	350		350
Issued March 2013, interest at 3.875% payable semi-annually, due March 2023	500		500
Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025	825		825
Issued May 2019, interest at 5.125% payable semi-annually, due May 2029	600		600
Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)	300		300
Issued October 2006, interest at 6.450% payable semi-annually, due November 2036	300		300
Issued September 2007, interest at 6.750% payable semi-annually, due September 2037	450		450
Issued March 2014, interest at 5.600% payable semi-annually, due April 2044	400		400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043	550		550
Credit agreement:
Revolving credit facility, weighted-average variable interest rate of 2.157%, as of March 31, 2020, due December 2024	800		200
Accounts receivable securitization facility:
Accounts receivable securitization facility, weighted-average variable interest rate of 1.88% as of March 31, 2020, due August 2022	350		350
Fair value adjustments related to interest rate swap fair value hedges (a)	19		19
Unamortized issuance costs	(36)		(37)
Unamortized discount, net	(8)		(8)
Finance lease liabilities	24		25
Total debt	5,924		5,924
Current finance lease liabilities	3		3
Current debt	—		600
Total long-term debt	$	5,921	$	5,321

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

Senior Notes and Junior Subordinated Notes

Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on their respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our Credit Agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to 5 consecutive years. The underwriters’ fees and related expenses are recorded in our condensed consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

Credit Agreement

We are a party to a $1.4 billion unsecured revolving Credit Agreement, which matures on December 9, 2024. The Credit Agreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million, subject to requisite lender approval. The Credit Agreement may be extended for up to two additional one-year periods subject to requisite lender approval. Loans under the Credit Agreement may be used for working capital and other general partnership purposes including acquisitions.

The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed 5.00 to 1.0 provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement), the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of the three consecutive fiscal quarters, including the fiscal quarter in which the Qualified Acquisition occurs.

Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.35% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1.00%, plus (b) an applicable margin of 0.35% based on our current credit rating. The Credit Agreement incurs an annual facility fee of 0.275% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.4 billion revolving credit facility.

As of March 31, 2020, we had unused borrowing capacity of $586 million, net of $14 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by the unused borrowing capacity of $586 million as of March 31, 2020. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the December 9, 2024 maturity date.

Accounts Receivable Securitization Facility

The Securitization Facility provides up to $350 million of borrowing capacity through August 2022 at LIBOR market index rates plus a margin. Under this Securitization Facility, certain of the Partnership’s wholly owned subsidiaries sell or contribute receivables to another of the Partnership’s consolidated subsidiaries, DCP Receivables LLC (“DCP Receivables”), a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility. 

DCP Receivables’ sole activity consists of purchasing receivables from the Partnership’s wholly owned subsidiaries that participate in the Securitization Facility and providing these receivables as collateral for DCP Receivables’ borrowings under the Securitization Facility.  DCP Receivables is a separate legal entity and the accounts receivable of DCP Receivables, up to the amount of the outstanding debt under the Securitization Facility, are not available to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. Any excess receivables are eligible to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. The amount available for borrowing may be limited by the availability of eligible receivables and other customary factors and conditions, as well as the covenants set forth in the Securitization Facility. As of March 31, 2020, DCP Receivables had $590 million of our accounts receivable securing borrowings of $350 million under the Securitization Facility.

The maturities of our debt as of March 31, 2020 are as follows:

	Debt Maturities
	(millions)
2021	500
2022	700
2023	500
2024	800
Thereafter	3,425
Total debt	$	5,925

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Commitments and Contingent Liabilities (Notes)

3 Months Ended

Mar. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

Commitments and Contingent Liabilities

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

Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (i) general liability insurance covering third-party exposures; (ii) statutory workers’ compensation insurance; (iii) automobile liability insurance for all owned, non-owned and hired vehicles; (iv) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (v) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (vi) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, pipeline safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) regulatory bodies and communities, and through litigation, on hydraulic fracturing and the real or perceived environmental or public health impacts of this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, (iii) state and federal regulatory officials regarding the emission of greenhouse gases and other air emissions, which could impose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.

The following pending proceedings involve governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment. It is not possible for us to predict the final outcome of these pending proceedings; however, we do not expect the outcome of one or more of these proceedings to have a material adverse effect to our results of operations, financial position, or cash flows:

•In 2018, the New Mexico Environment Department (“NMED”) issued two separate Notices of Violation (“NOV”) relating to upset and malfunction event emissions at two of our gas processing plants. Following information exchanges and discussions with NMED regarding the events and the propriety of the alleged violations, in February 2019 we entered into preliminary settlement agreements to resolve the alleged violations under each NOV for administrative penalties approximating $150,000 and $142,000, respectively. We intend to mitigate a portion of each administrative penalty through the implementation of environmentally beneficial projects.

•In 2018, the Colorado Department of Public Health and Environment (“CDPHE”) issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants that we self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the plant's air permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as an economic benefit payment generally covering the period when the flare was required to be included in the facility air permit, in a combined amount expected to be between approximately $375,000 and $460,000. We are still evaluating and holding discussions with CDPHE as to the foregoing amounts and proposed settlement terms.

•In January 2019, CDPHE issued a Compliance Advisory in relation to an improperly configured facility flare meter, which failed to accurately track air emissions from the flare at one of our gas processing plants resulting in the flare exceeding its permitted emissions limits. Following information exchanges and discussions with CDPHE, a resolution was agreed upon in December 2019 that included DCP completing a project to reduce levels of vapors directed to the flare, amending the air permit, and paying an administrative penalty of approximately $37,000, and making expenditures on an environmentally beneficial project of approximately $149,000. DCP made the required payment and expenditures in the first quarter of 2020 and this proceeding is now complete.

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Subsequent Events (Notes)

3 Months Ended

Mar. 31, 2020

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

On April 21, 2020, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.39 per common unit. The distribution will be paid on May 15, 2020 to unitholders of record on May 1, 2020.

On the same date, we announced that the board of directors of the General Partner declared a semi-annual distribution on our Series A Preferred Units of $36.875 per unit. The distribution will be paid on June 15, 2020 to unitholders of record on June 1, 2020.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and $0.4969 per unit, respectively. The Series B distributions will be paid on June 15, 2020 to unitholders of record on June 1, 2020. The Series C distribution will be paid on July 15, 2020 to unitholders of record on July 1, 2020.

On April 13th, 2020, we announced a 15% workforce reduction, which will result in $11 million of non-recurring expense in the second quarter of 2020.

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Accounting Policies	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	2. Update to Significant Accounting PoliciesCash, Cash Equivalents, and Restricted Cash - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents. Restricted cash primarily consists of amounts held in our non-qualified deferred compensation plan. Restricted cash is excluded from cash and cash equivalents and is included in other current or non-current assets.

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ (549)	$ 76
Other comprehensive income:
Other comprehensive income	0	0
Other comprehensive income	0	0
Total comprehensive income	(549)	76
Total comprehensive income attributable to noncontrolling interests	(1)	(1)
Total comprehensive income attributable to partners	$ (550)	$ 75

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Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) - Commodity derivatives - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	$ 252	$ 32
Long- Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	53	2
Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	192	58
Long- Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	46	20
Level 1 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	233	13
Level 1 | Long- Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	47	1
Level 1 | Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	169	15
Level 1 | Long- Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	34	2
Level 2 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	11	15
Level 2 | Long- Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	5	1
Level 2 | Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	20	42
Level 2 | Long- Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	11	15
Level 3 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	8	4
Level 3 | Long- Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - assets	1	0
Level 3 | Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	3	1
Level 3 | Long- Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives - liabilities	$ 1	$ (3)

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Leases, Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Lessee, Lease, Description [Line Items]
Operating Lease Extension Term	20
Operating Lease, Payments	$ 7	$ 6
Finance Lease, Interest Payment on Liability	1	0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 0	$ 6
Finance Lease, Weighted Average Remaining Lease Term	6 years
Finance Lease, Weighted Average Discount Rate, Percent	3.00%
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	1 year
Lessee, Finance Lease, Renewal Term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	21 years
Lessee, Finance Lease, Renewal Term	21 years

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Leases, Supplemental Cash Flow and Other Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Lessee Disclosure [Abstract]
Operating Lease, Payments	$ 7	$ 6
Finance Lease, Interest Payment on Liability	1	0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 0	$ 6
Operating Lease, Weighted Average Remaining Lease Term	6 years	6 years
Finance Lease, Weighted Average Remaining Lease Term	6 years
Operating Lease, Weighted Average Discount Rate, Percent	4.00%	4.00%
Finance Lease, Weighted Average Discount Rate, Percent	3.00%

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Contract Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Contract Assets and Liabilities [Abstract]
Contract with Customer, Liability	$ 34	$ 33
Contract with Customer, Liability, Additions	2
Contract with Customer, Liability, Revenue Recognized	$ (1)
Contract with Customer, Timing of Satisfaction of Performance Obligation and Payment	35 years

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Business Segments (Tables)

3 Months Ended

Mar. 31, 2020

Segment Reporting [Abstract]

Segment Information

Three Months Ended March 31, 2020: 

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	1,358	$	913	$	—	$	(614)	$	1,657
Gross margin (a)	$	111	$	400	$	—	$	—	$	511
Operating and maintenance expense	(7)		(142)		(4)		—		(153)
Depreciation and amortization expense	(3)		(89)		(7)		—		(99)
General and administrative expense	(2)		(3)		(51)		—		(56)
Asset impairments	—		(746)		—		—		(746)
Other expense, net	—		(3)		—		—		(3)
Earnings from unconsolidated affiliates	137		(61)		—		—		76
Interest expense	—		—		(78)		—		(78)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	236	$	(644)	$	(141)	$	—	$	(549)
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	236	$	(645)	$	(141)	$	—	$	(550)
Non-cash derivative mark-to-market (b)	$	42	$	92	$	—	$	—	$	134
Non-cash lower of cost or net realizable value adjustments	$	4	$	—	$	—	$	—	$	4
Capital expenditures	$	1	$	67	$	1	$	—	$	69
Investments in unconsolidated affiliates, net	$	34	$	—	$	—	$	—	$	34

Three Months Ended March 31, 2019:

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	2,045	$	1,288	$	—	$	(1,134)	$	2,199
Gross margin (a)	$	58	$	337	$	—	$	—	$	395
Operating and maintenance expense	(9)		(165)		(4)		—		(178)
Depreciation and amortization expense	(3)		(93)		(7)		—		(103)
General and administrative expense	(3)		(6)		(58)		—		(67)
Other expense, net	—		(5)		—		—		(5)
Loss on sale of assets, net	(9)		—		—		—		(9)
Earnings from unconsolidated affiliates	113		—		—		—		113
Interest expense	—		—		(69)		—		(69)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	147	$	68	$	(139)	$	—	$	76
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	147	$	67	$	(139)	$	—	$	75
Non-cash derivative mark-to-market (b)	$	(18)	$	(36)	$	—	$	—	$	(54)
Non-cash lower of cost or net realizable value adjustments	$	5	$	—	$	—	$	—	$	5
Capital expenditures	$	14	$	165	$	3	$	—	$	182
Investments in unconsolidated affiliates, net	$	131	$	—	$	—	$	—	$	131

	March 31,		December 31,
	2020		2019
	(millions)
Segment long-term assets:
Gathering and Processing	$	8,101	$	8,904
Logistics and Marketing	3,861		3,848
Other (c)	268		295
Total long-term assets	12,230		13,047
Current assets	958		1,080
Total assets	$	13,188	$	14,127

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

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

(c)Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.

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Net Income or Loss per Limited Partner Unit (Notes)

3 Months Ended

Mar. 31, 2020

Earnings Per Share [Abstract]

Net Income or Loss per Limited Partner Unit

16. Net Income or Loss per Limited Partner Unit

Prior to the equity restructuring transaction, we used the two-class method when calculating the net income unit applicable to limited partners, because we had more than one participating security consisting of limited partner common units, general partner units and IDRs. Subsequent to the equity restructuring transaction that occurred on November 6, 2019, our general partner and its IDRs no longer participate in earnings or distributions.

There were 350,820 restricted phantom units outstanding as of March 31, 2020 that were excluded from the calculation of diluted net loss per unit for the periods presented because including them would have been anti-dilutive. We have the ability to elect to settle restricted phantom units at our discretion in either cash or common units. For units granted during 2020, we have the ability and intent to settle vested units through the issuance of common units.

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Supplemental Cash Flow Information (Notes)

3 Months Ended

Mar. 31, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

	Three Months Ended March 31,
	2020		2019
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	88	$	65
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	16	$	40
Other non-cash activities:
Operating lease assets arising from the implementation of Topic 842	$	—	$	84
Right-of-use assets obtained in exchange for operating and finance lease liabilities	$	—	$	6

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2020	May 01, 2020
Cover [Abstract]
Entity Registrant Name	DCP MIDSTREAM, LP
Document Period End Date	Mar. 31, 2020
Amendment Flag	false
Document Fiscal Year Focus	2020
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Document Fiscal Period Focus	FY
Entity Central Index Key	0001338065
Current Fiscal Year End Date	--03-31
Document Type	10-Q
City Area Code	(303)
Local Phone Number	595-3331
Entity Address, Postal Zip Code	80202
Entity Address, Address Line One	370 17th Street
Entity Address, Address Line Two	Suite 2500
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Current Reporting Status	Yes
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	03-0567133
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	001-32678
Entity Shell Company	false
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding		208,329,928
Series B Preferred Limited Partners [Member]
Title of 12(b) Security	7.875% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	DCP PRB
Security Exchange Name	NYSE
Series C Preferred Limited Partners [Member]
Title of 12(b) Security	7.95% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	DCP PRC
Security Exchange Name	NYSE
Limited Partners
Title of 12(b) Security	Common units representing limited partnership interests
Trading Symbol	DCP
Security Exchange Name	NYSE

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Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Series A Preferred Limited Partners [Member]	Series B Preferred Limited Partners [Member]	Series C Preferred Limited Partners [Member]	Limited Partners	General Partner	Accumulated Other Comprehensive (Loss) Income	Noncontrolling Interests
Beginning balance at Dec. 31, 2018	$ 7,297	$ 489	$ 156	$ 106	$ 6,418	$ 107	$ (8)	$ 29
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	76	9	3	2	20	41	0	1
Other comprehensive income	0
Total Cash Distribution to Unitholders	(159)	0	(3)	(2)	(111)	(43)	0	0
Distributions to noncontrolling interests	(1)	0	0	0	0	0	0	1
Ending balance at Mar. 31, 2019	7,213	498	156	106	6,327	$ 105	(8)	29
Beginning balance at Dec. 31, 2019	6,633	489	156	106	5,861		(7)	28
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	(549)	9	3	2	(564)		0	1
Other comprehensive income	0
Total Cash Distribution to Unitholders	(167)	0	(3)	(2)	(162)		0	0
Distributions to noncontrolling interests	(1)	0	0	0	0		0	(1)
Ending balance at Mar. 31, 2020	$ 5,916	$ 498	$ 156	$ 106	$ 5,135		$ (7)	$ 28

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Recent Accounting Pronouncements (Notes)

3 Months Ended

Mar. 31, 2020

Recent Accounting Pronouncements, Policy [Abstract]

Recent Accounting Pronouncements and Changes in Accounting Principles [Text Block]

. Recent Accounting PronouncementsFASB ASU, 2020-04 “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” or ASU 2020-04 - In March 2020, the FASB issued ASU 2020-04, which provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This ASU is effective for interim and annual reporting periods that include or are subsequent to March 12, 2020. We adopted this ASU on March 12, 2020 and it did not have a material impact on our condensed consolidated financial statements.

FASB ASU, 2018-15 “Intangibles - Goodwill and Other - Internal-use Software (Subtopic 350-40): Customers Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract” or ASU 2018-15 - In August 2018, the FASB issued ASU 2018-15, which aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service contract with the guidance on capitalizing costs associated with developing or obtaining internal-use software. This ASU is effective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have not been issued. We adopted this ASU on January 1, 2020 and it did not have a material impact on our condensed consolidated financial statements.

FASB ASU, 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” or ASU 2016-13 - In June 2016, the FASB issued ASU 2016-13, which amends current measurement techniques used to estimate credit losses for financial assets. This ASU is effective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have not been issued. We adopted this ASU on January 1, 2020 and it did not have a material impact on our condensed consolidated financial statements.

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Leases, Schedule of Minimum Operating and Finance Lease Payments (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Year One	$ 20
Lessee, Operating Lease, Liability, Payments, Due Year Two	25
Lessee, Operating Lease, Liability, Payments, Due Year Three	22
Lessee, Operating Lease, Liability, Payments, Due Year Four	17
Lessee, Operating Lease, Liability, Payments, Due Year Five	9
Lessee, Operating Lease, Liability, Payments, Due after Year Five	29
Lessee, Operating Lease, Liability, Payments, Due	122
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	16
Operating Lease, Liability	106
Finance Lease, Liability, Payments, Year One	4
Finance Lease, Liability, Payments, Due Year Two	4
Finance Lease, Liability, Payments, Due Year Three	4
Finance Lease, Liability, Payments, Due Year Four	4
Finance Lease, Liability, Payments, Due Year Five	3
Finance Lease, Liability, Payments, Due after Year Five	8
Finance Lease, Liability, Payments, Due	27
Finance Lease, Liability, Undiscounted Excess Amount	3
Finance Lease, Liability	$ 24	$ 25

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Fair Value Measurement - Impairment (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020 USD ($)	Mar. 31, 2019 USD ($)
Impaired Long-Lived Assets Held and Used [Line Items]
Property, Plant, and Equipment	$ 96
Goodwill	0
Assets	352
Property, plant, and equipment impairment	587
Goodwill, Impairment Loss	159
Asset Impairment	746	$ 0
Equity Method Investment, Other than Temporary Impairment	61
Equity Method Investments, Fair Value Disclosure	256
Total Impairment Charges, including Equity Method Investments	807
Permian Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Property, plant, and equipment impairment	461
South Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Property, plant, and equipment impairment	126
Level 1
Impaired Long-Lived Assets Held and Used [Line Items]
Property, Plant, and Equipment	0
Goodwill	0
Assets	0
Equity Method Investments, Fair Value Disclosure	0
Level 2
Impaired Long-Lived Assets Held and Used [Line Items]
Property, Plant, and Equipment	0
Goodwill	0
Assets	0
Equity Method Investments, Fair Value Disclosure	0
Level 3
Impaired Long-Lived Assets Held and Used [Line Items]
Property, Plant, and Equipment	96
Goodwill	0
Assets	352
Equity Method Investments, Fair Value Disclosure	$ 256
Level 3 | Valuation Technique, Discounted Cash Flow | Measurement Input, Discount Rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	14
Level 3 | Valuation Technique, Discounted Cash Flow | Measurement Input, Terminal Value Multiple
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	8
Level 3 | Arithmetic Average | Market Approach Valuation Technique | Measurement Input, EBITDA Multiple
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Goodwill, Measurement Input	8
Level 3 | Arithmetic Average | Oil | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	55.98
Level 3 | Arithmetic Average | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	3.35
Level 3 | Arithmetic Average | Natural Gas Liquids | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	0.52
Level 3 | Minimum | Market Approach Valuation Technique | Measurement Input, EBITDA Multiple
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Goodwill, Measurement Input	5.2
Level 3 | Minimum | Oil | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	34.52
Level 3 | Minimum | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	2.28
Level 3 | Minimum | Natural Gas Liquids | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	0.30
Level 3 | Maximum | Market Approach Valuation Technique | Measurement Input, EBITDA Multiple
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Goodwill, Measurement Input	16.5
Level 3 | Maximum | Oil | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	67.61
Level 3 | Maximum | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	4.12
Level 3 | Maximum | Natural Gas Liquids | Valuation Technique, Discounted Cash Flow | Measurement Input, Commodity Future Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Assets, Measurement Input	0.62

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Carrying Value and Fair Value of Debt (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Total Debt, Carrying Value	$ 5,936	$ 5,936
Total Debt, Fair Value	$ 4,252	$ 6,130

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Agreements and Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating Expense
Related Party Transaction [Line Items]
Labor and related expense	$ 44	$ 49
General and Administrative Expense
Related Party Transaction [Line Items]
Labor and related expense	$ 35	$ 47

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Statement of Cash Flows, Supplemental Disclosures (Tables)

3 Months Ended

Mar. 31, 2020

Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]

Summary of Supplemental Cash Flow Information

	Three Months Ended March 31,
	2020		2019
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	88	$	65
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	16	$	40
Other non-cash activities:
Operating lease assets arising from the implementation of Topic 842	$	—	$	84
Right-of-use assets obtained in exchange for operating and finance lease liabilities	$	—	$	6

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Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Derivative Asset [Abstract]
Derivative Instruments and Hedges, Current Assets	$ 252	$ 32
Derivative Instruments and Hedges, Assets, Noncurrent	53	2
Derivative Liability [Abstract]
Derivative Instruments and Hedges, Current Liabilities	192	58
Derivative Instruments and Hedges, Liabilities, Noncurrent	46	20
Commodity derivatives | Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Derivative Instruments and Hedges, Current Assets	252	32
Derivative Instruments and Hedges, Assets, Noncurrent	53	2
Derivative Instruments Not Designated as Hedging Instruments, Total Assets, at Fair Value	305	34
Commodity derivatives | Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Derivative Instruments and Hedges, Current Liabilities	192	58
Derivative Instruments and Hedges, Liabilities, Noncurrent	46	20
Derivative Instruments Not Designated as Hedging Instruments, Total Liabilities, at Fair Value	$ 238	$ 78

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Business Segments - Segment Assets (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	$ 12,230	$ 13,047
Current assets	958	1,080
Total assets	13,188	14,127
Operating Segments | Logistics and Marketing
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	3,861	3,848
Operating Segments | Gathering and Processing
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	8,101	8,904
Other
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	$ 268	$ 295

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Net Income or Loss per Limited Partner Unit Additional Detail (Details)	3 Months Ended
	Mar. 31, 2020 shares
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	350,820

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Debt - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description	$ 500
Accounts Receivable Securitization Facility
Debt Instrument [Line Items]
Accounts Recievable included in the Securitization Transaction	590
Line of Credit Facility, Maximum Borrowing Capacity	350
Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,400
Basis spread determined by credit rating	0.35%
Commitment fee percentage	0.275%
Letter of credit amount outstanding	$ 14
Debt covenants, maximum borrowing amount	$ 586
Credit Agreement | LIBOR
Debt Instrument [Line Items]
Variable rate basis spread	1.35%
Credit Agreement | Federal Funds Rate
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
Credit Agreement | LIBOR Market Index
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Credit Agreement | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio in event of acquisition	5.50
Credit Agreement | Quarters After June 30, 2018 | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5.00
Credit Agreement | Quarters After June 30, 2018 | Minimum
Debt Instrument [Line Items]
Maximum leverage ratio	1.0
Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025 | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 825	$ 825
Debt Instrument, Interest Rate, Stated Percentage	5.375%
Issued May 2019, interest at 5.125% payable semiannually, due May 2029 | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 600	$ 600
Debt Instrument, Interest Rate, Stated Percentage	5.125%

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Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued (in shares)	208,329,928
Total Cash Distribution	$ 167	$ 159
DCP Midstream LP | DCP Midstream, LLC
Partnership Equity And Distribution [Line Items]
Ownership interest percentage by parent	57.00%
Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Offer Value Of Common Stock Unit Remaining Available For Sale	$ 750

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Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 13,342	$ 14,504
Accumulated depreciation	(5,162)	(5,693)
Property, plant and equipment, net	8,180	8,811
Gathering and transmission systems
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 7,677	8,406
Gathering and transmission systems | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	20 years
Gathering and transmission systems | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	50 years
Processing, storage and terminal facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 4,873	5,305
Processing, storage and terminal facilities | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	35 years
Processing, storage and terminal facilities | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	60 years
Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 577	585
Other | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	3 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	30 years
Finance lease assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 21	25
Finance lease assets [Member] | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	4 years
Finance lease assets [Member] | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	7 years
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 194	$ 183

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Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 3,681	$ 3,724
DCP Sand Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	66.67%
Investments in unconsolidated affiliates	$ 1,768	1,764
DCP Southern Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	66.67%
Investments in unconsolidated affiliates	$ 742	738
Front Range Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	33.33%
Investments in unconsolidated affiliates	$ 209	206
Gulf Coast Express [Member]
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	25.00%
Investments in unconsolidated affiliates	$ 445	449
Texas Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	10.00%
Investments in unconsolidated affiliates	$ 100	101
Cheyenne Connector
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	50.00%
Investments in unconsolidated affiliates	$ 100	83
Mont Belvieu Enterprise Fractionator
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	12.50%
Investments in unconsolidated affiliates	$ 27	27
Mont Belvieu 1 Fractionator
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	20.00%
Investments in unconsolidated affiliates	$ 8	9
Discovery Producer Services LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	40.00%
Investments in unconsolidated affiliates	$ 256	322
Panola Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	15.00%
Investments in unconsolidated affiliates	$ 22	22
Other
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 4	$ 3

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Fair Value Measurement (Tables)

3 Months Ended

Mar. 31, 2020

Fair Value Disclosures [Abstract]

Details of Impairment of Long-Lived Assets Held and Used by Asset

	Fair Value Measurements Using Inputs Considered as
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
Long-lived assets	$	96	$	—	$	—	$	96	$	587
Goodwill	—		—		—		—		159
Direct investment in unconsolidated affiliate	256		—		—		256		61
Total impairments	$	352	$	—	$	—	$	352	$	807

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques

	March 31, 2020
Asset Groups	Valuation Techniques	Unobservable Inputs	Range (low-high) (a)	Average (b)
Long-lived assets, investment in unconsolidated affiliate, goodwill	Discounted cash flow	Oil prices	$34.52 - $67.61	$	55.98	Per barrel
		Natural gas prices	$2.28 - $4.12	$	3.35	Per MMBtu
		NGL prices	$0.30 - $0.62	$	0.52	Per gallon
		Discount rate	14%	14%
		Terminal value multiple	8x	8x
Goodwill	Market comparable companies	EBITDA multiple	5.2x - 16.5x	8x

Financial Instruments Carried at Fair Value

	March 31, 2020								December 31, 2019
	Level 1		Level 2		Level 3		Total Carrying Value		Level 1		Level 2		Level 3		Total Carrying Value
	(millions)
Current assets:
Commodity derivatives	$	233	$	11	$	8	$	252	$	13	$	15	$	4	$	32
Long-term assets:
Commodity derivatives	$	47	$	5	$	1	$	53	$	1	$	1	$	—	$	2
Current liabilities:
Commodity derivatives	$	(169)	$	(20)	$	(3)	$	(192)	$	(15)	$	(42)	$	(1)	$	(58)
Long-term liabilities:
Commodity derivatives	$	(34)	$	(11)	$	(1)	$	(46)	$	(2)	$	(15)	$	(3)	$	(20)

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation

	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended March 31, 2020 (a):
Beginning balance	$	4	$	—	$	(1)	$	(3)
Net unrealized gains included in earnings	8		1		5		2
Settlements	(4)		—		(7)		—
Ending balance	$	8	$	1	$	(3)	$	(1)
Three months ended March 31, 2019 (a):
Beginning balance	$	14	$	2	$	—	$	(2)
Net unrealized (losses) gains included in earnings	(4)		(1)		(2)		1
Transfers out of Level 3	(2)		—		—		—
Settlements	(3)		—		1		—
Ending balance	$	5	$	1	$	(1)	$	(1)

(a)There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three months ended March 31, 2020 and 2019.

Schedule of Valuation Processes

	March 31, 2020
Product Group	Fair Value		Valuation Techniques	Unobservable Input	Forward Curve Range	Weighted Average (a)
	(millions)
Assets
NGLs	$	9	Market approach	Longer dated forward curve prices	$0.11-$0.47	$0.33	Per gallon
Liabilities
NGLs	$	(3)	Market approach	Longer dated forward curve prices	$0.10-$0.53	$0.27	Per gallon
Natural gas	$	(1)	Market approach	Longer dated forward curve prices	$1.63-$2.50	$1.99	Per MMBtu

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

March 31, 2020 and December 31, 2019, the carrying value and fair value of our total debt, including current maturities, were as follows:

		March 31, 2020				December 31, 2019
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)
Total debt		$	5,936	$	4,252	$	5,936	$	6,130

(a) Excludes unamortized issuance costs and finance lease liabilities.

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Inventories (Tables)

3 Months Ended

Mar. 31, 2020

Inventory Disclosure [Abstract]

Schedule of Inventories

Inventories were as follows: 

	March 31, 2020		December 31, 2019
	(millions)
Natural gas	$	17	$	19
NGLs	9		27
Total inventories	$	26	$	46

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Leases (Notes)

3 Months Ended

Mar. 31, 2020

Leases [Abstract]

Leases of Lessee Disclosure [Text Block]

12. Leases

We have operating leases for transportation agreements, office space, vehicles, and field equipment. We have finance leases for field equipment and vehicles. Our leases have remaining lease terms ranging from less than one year to 21 years, some of which may include options to extend leases up to 20 years, and some of which may include options to terminate the leases in less than one year. Extension options on certain compressors and field equipment were included in the lease terms used to calculate our operating lease assets and liabilities as it is reasonably certain that we exercise those options. Operating and finance leases are included on our condensed consolidated balance sheet as follows:

	Location in Condensed Consolidated Balance Sheet	As of
		March 31, 2020		December 31, 2019
		(millions)
Assets
Operating lease assets	Operating lease assets	$	98	$	107
Finance lease assets	Property, plant and equipment	21		25
Total right of use assets		119		132
Liabilities
Current liabilities
Operating lease liabilities	Other current liabilities	$	23	$	24
Finance lease liabilities	Current debt	3		3
Noncurrent liabilities
Operating lease liabilities	Operating lease liabilities	$	83	$	88
Finance lease liabilities	Long-term debt	21		22
Total lease liabilities		$	130	$	137

Variable lease costs primarily consist of common area maintenance on our office spaces and variable transportation costs. Finance lease cost was immaterial for the three months ended March 31, 2020 and 2019, respectively. The components of lease expense are as follows:

	Location in Condensed Consolidated Statement of Operations	Three Months Ended March 31,
		2020		2019
		(millions)
Operating lease cost	Operating and maintenance expense	$	8	$	6
Variable lease cost	Operating and maintenance expense	2		2
Short term lease cost	Operating and maintenance expense	1		1
Total lease cost		$	11	$	9

Maturities of operating and finance lease liabilities under non-cancelable leases as of March 31, 2020 are as follows:

	Future Minimum Lease Payments as of March 31, 2020
	Operating Leases		Finance Leases
	(millions)
2020 - remainder	$	20	$	4
2021	25		4
2022	22		4
2023	17		4
2024	9		3
Thereafter	29		8
Total lease payments	$	122	$	27
Less imputed interest	(16)		(3)
Total lease liabilities	$	106	$	24

Supplemental cash flow information related to leases is as follows:

	Three Months Ended March 31,
	2020			2019
	(millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	7		$	6
Operating cash flows from finance leases	1			—
Right-of-use assets obtained in exchange for operating lease obligations:	$	—		$	6
Other information related to operating leases as follows:
Weighted average remaining lease term	6 years			6 years
Weighted average discount rate	4.00		%	4.00		%
Other information related to finance leases as follows:
Weighted average remaining lease term	6 years			—
Weighted average discount rate	3.00		%	—		%

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Revenue Recognition (Notes)

3 Months Ended

Mar. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue from External Customers by Products and Services [Table Text Block]

. Revenue Recognition

We disaggregate our revenue from contracts with customers by type of contract for each of our reportable segments, as we believe it best depicts the nature, timing and uncertainty of our revenue and cash flows. The following tables set forth our revenue by those categories:

	Three Months Ended March 31, 2020
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	411	$	326	$	(290)	$	447
Sales of NGLs and condensate (a)	883		387		(324)		946
Transportation, processing and other	13		99		—		112
Trading and marketing gains, net (b)	51		101		—		152
Total operating revenues	$	1,358	$	913	$	(614)	$	1,657

	Three Months Ended March 31, 2019
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	637	$	557	$	(498)	$	696
Sales of NGLs and condensate (a)	1,403		648		(636)		1,415
Transportation, processing and other	12		103		—		115
Trading and marketing losses, net (b)	(7)		(20)		—		(27)
Total operating revenues	$	2,045	$	1,288	$	(1,134)	$	2,199

(a)   Includes $591 million and $858 million for the three months ended March 31, 2020 and 2019, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment, which are not within the scope of Topic 606.

(b)   Not within the scope of Topic 606.

The revenue expected to be recognized in the future related to performance obligations that are not satisfied is approximately $383 million as of March 31, 2020. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to be recognized through 2028 with a weighted average remaining life of four years as of March 31, 2020. As a practical expedient permitted by Topic 606, this amount excludes variable consideration as well as remaining performance obligations that have original expected durations of one year or less, as applicable. Our remaining performance obligations also exclude estimates of variable rate escalation clauses in our contracts with customers.

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Property, Plant and Equipment (Notes)

3 Months Ended

Mar. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

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

	Depreciable Life	March 31, 2020		December 31, 2019
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,677	$	8,406
Processing, storage and terminal facilities	35 — 60 Years	4,873		5,305
Other	3 — 30 Years	577		585
Finance lease assets	4 — 7 Years	21		25
Construction work in progress		194		183
Property, plant and equipment		13,342		14,504
Accumulated depreciation		(5,162)		(5,693)
Property, plant and equipment, net		$	8,180	$	8,811

Interest capitalized on construction projects was $2 million and $5 million for the three months ended March 31, 2020 and 2019, respectively.

Depreciation expense was $97 million and $101 million for the three months ended March 31, 2020 and 2019, respectively.

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Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating revenues:
Trading and marketing gains (losses), net	$ 152	$ (27)
Total operating revenues	1,657	2,199
Operating costs and expenses:
Operating and maintenance expense	153	178
Depreciation and amortization expense	99	103
General and administrative expense	56	67
Other expense, net	(3)	(5)
Asset Impairment	746	0
Loss on sale of assets, net	0	9
Total operating costs and expenses	2,203	2,166
Operating (loss) income	(546)	33
Earnings from unconsolidated affiliates	76	113
Interest expense, net	(78)	(69)
(Loss) income before income taxes	(548)	77
Income tax expense	1	1
Net income	(549)	76
Net income attributable to noncontrolling interests	(1)	(1)
Net income attributable to partners	(550)	75
Series A preferred limited partners' interest in net income	(9)	(9)
Series B preferred limited partners' interest in net income	(3)	(3)
Series C preferred limited partners' interest in net income	(2)	(2)
General partner’s interest in net income	0	(41)
Net income allocable to limited partners	$ (564)	$ 20
Net income per limited partner unit — basic and diluted	$ (2.71)	$ 0.14
Weighted Average Number of Limited Partnership and General Partnership Unit Outstanding, Basic and Diluted	208.3	143.3
Property, plant, and equipment impairment	$ 587
Natural Gas, NGLs and Condensate [Member] | Third Party
Operating revenues:
Sales of natural gas, NGLs and condensate	1,171	$ 1,771
Operating costs and expenses:
Purchases and related costs	872	1,533
Transportation, Processing and Other [Member]
Operating revenues:
Sales of natural gas, NGLs and condensate	112	115
Affiliated Entity | Natural Gas, NGLs and Condensate [Member]
Operating revenues:
Sales of natural gas, NGLs and condensate	222	340
Operating costs and expenses:
Purchases and related costs	36	62
Affiliated Entity | Transportation Fees
Operating costs and expenses:
Purchases and related costs	$ 238	$ 209

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Description of Business and Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

1. Description of Business and Basis of Presentation

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

Our Partnership includes our Logistics and Marketing and Gathering and Processing segments. For additional information regarding these segments, see Note 18 - Business Segments.

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and which is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Enbridge Inc. and its affiliates, or Enbridge. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of March 31, 2020, DCP Midstream, LLC, together with our general partner, owned approximately 57% of us through limited partner interests.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

The condensed consolidated financial statements have been prepared in accordance with GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could differ from these estimates, which may be significantly impacted by various factors, including those outside of our control, such as the impact of a sustained deterioration in commodity prices and volumes, which would negatively impact our results of operations, financial condition and cash flows. All intercompany balances and transactions have been eliminated in consolidation.

These unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three months ended March 31, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2019 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019.

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Risk Management and Hedging Activities (Notes)

3 Months Ended

Mar. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management and Hedging Activities

Risk Management and Hedging Activities

Our 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 and a risk management committee (the “Risk Management Committee”), to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

Collateral

As of March 31, 2020, we had cash deposits of $35 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of March 31, 2020, we held letters of credit of $44 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.

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

Offsetting

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

	March 31, 2020						December 31, 2019
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount		Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount
	(millions)
Assets:
Commodity derivatives	$	305	$	—	$	305	$	34	$	—	$	34
Liabilities:
Commodity derivatives	$	(238)	$	—	$	(238)	$	(78)	$	—	$	(78)

 Summarized Derivative Information

The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2020 and December 31, 2019.

Balance Sheet Line Item	March 31, 2020		December 31, 2019		Balance Sheet Line Item	March 31, 2020		December 31, 2019
	(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	$	252	$	32	Unrealized losses on derivative instruments — current	$	(192)	$	(58)
Unrealized gains on derivative instruments — long-term	53		2		Unrealized losses on derivative instruments — long-term	(46)		(20)
Total	$	305	$	34	Total	$	(238)	$	(78)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2020:

	Interest Rate Cash Flow Hedges		Commodity Cash Flow Hedges		Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(2)	$	(6)	$	1	$	(7)
Net deferred (losses) gains in AOCI (ending balance)	$	(2)	$	(6)	$	1	$	(7)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1)	$	—	$	—	$	(1)

(a)Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2019:

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

(a)Relates to Discovery, an unconsolidated affiliate.

For the three months ended March 31, 2020 and 2019, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2020 and 2019, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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

Commodity Derivatives: Statements of Operations Line Item		Three Months Ended March 31,
		2020		2019
	(millions)
Realized gains		$	18	$	27
Unrealized gains (losses)		134		(54)
Trading and marketing gains (losses), net		$	152	$	(27)

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

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

	March 31, 2020
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long Position (MMBtu)
2020	(1,410,000)	(27,659,800)	(25,009,803)	8,190,000
2021	(1,467,000)	(45,540,000)	(7,294,133)	4,325,000
2022	(107,000)	(13,687,500)	(104,842)	8,212,500
2023	—	—	—	7,300,000
2024	—	—	—	2,140,000
	March 31, 2019
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long (Short) Position (MMBtu)
2019	(1,191,000)	(32,148,650)	(26,987,090)	2,102,500
2020	(283,000)	(930,000)	(14,388,830)	3,660,000
2021	(100,000)	—	(5,516,168)	(3,650,000)
2022	—	—	(175)	—

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Restructuring (Notes)	3 Months Ended
	Mar. 31, 2020
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	Restructuring CostsIn May 2019, we announced a voluntary separation program which resulted in of nonrecurring expense for the year ended December 31, 2019. We do not expect to incur any additional expense in relation to the voluntary separation program.

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Description of Business and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Significant Accounting Policies [Text Block]

The condensed consolidated financial statements have been prepared in accordance with GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could differ from these estimates, which may be significantly impacted by various factors, including those outside of our control, such as the impact of a sustained deterioration in commodity prices and volumes, which would negatively impact our results of operations, financial condition and cash flows.

Business Description and Basis of Presentation [Text Block]

The condensed consolidated financial statements have been prepared in accordance with GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could differ from these estimates, which may be significantly impacted by various factors, including those outside of our control, such as the impact of a sustained deterioration in commodity prices and volumes, which would negatively impact our results of operations, financial condition and cash flows. All intercompany balances and transactions have been eliminated in consolidation.

These unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three months ended March 31, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2019 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019.

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Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Accounts receivable	$ 98	$ 138
Accounts payable	97	100
Unconsolidated Affiliates
Related Party Transaction [Line Items]
Accounts receivable	17	21
Accounts payable	70	78
Phillips 66
Related Party Transaction [Line Items]
Accounts receivable	81	117
Accounts payable	27	20
Enbridge
Related Party Transaction [Line Items]
Accounts payable	$ 0	$ 2

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Disaggregation of Revenue [Line Items]
Trading and marketing gains (losses), net	$ 152	$ (27)
Total operating revenues	1,657	2,199
Revenue, Remaining Performance Obligation, Amount	$ 383
Revenue, Performance Obligation, Description of Timing	four years
Revenue from contract with customer not within the scope of Topic 606	$ 591	858
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	447	696
NGLs and Condensate [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	946	1,415
Transportation, Processing and Other [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	112	115
Gathering and Processing
Disaggregation of Revenue [Line Items]
Trading and marketing gains (losses), net	101	(20)
Total operating revenues	913	1,288
Gathering and Processing | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	326	557
Gathering and Processing | NGLs and Condensate [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	387	648
Gathering and Processing | Transportation, Processing and Other [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	99	103
Logistics and Marketing
Disaggregation of Revenue [Line Items]
Trading and marketing gains (losses), net	51	(7)
Total operating revenues	1,358	2,045
Logistics and Marketing | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	411	637
Logistics and Marketing | NGLs and Condensate [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	883	1,403
Logistics and Marketing | Transportation, Processing and Other [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	13	12
Eliminations
Disaggregation of Revenue [Line Items]
Trading and marketing gains (losses), net	0	0
Total operating revenues	(614)	(1,134)
Eliminations | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	(290)	(498)
Eliminations | NGLs and Condensate [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate	$ (324)	(636)
Eliminations | Transportation, Processing and Other [Member]
Disaggregation of Revenue [Line Items]
Sales of natural gas, NGLs and condensate		$ 0

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Partnership Equity and Distributions (Tables)

3 Months Ended

Mar. 31, 2020

Equity [Abstract]

Cash Distribution

Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
February 14, 2020	$	0.78	$	162
November 14, 2019	$	0.78	$	155
August 14, 2019	$	0.78	$	154
May 15, 2019	$	0.78	$	155
February 14, 2019	$	0.78	$	154
Distributions to Series A Preferred unitholders
December 16, 2019	$	36.875	$	19
June 17, 2019	$	36.875	$	18
Distributions to Series B Preferred unitholders
March 16, 2020	$	0.4922	$	3
December 16, 2019	$	0.4922	$	4
September 16, 2019	$	0.4922	$	3
June 17, 2019	$	0.4922	$	3
March 15, 2019	$	0.4922	$	3
Distributions to Series C Preferred unitholders
January 15, 2020	$	0.4969	$	2
October 15, 2019	$	0.4969	$	2
July 15, 2019	$	0.4969	$	3
April 15, 2019	$	0.4969	$	2
January 15, 2019	$	0.5576	$	2

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Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Current Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Ending balance	$ 4	$ 14
Net realized and unrealized gains (losses) included in earnings	8	(4)
Transfers out of Level 3		(2)
Settlements	(4)	(3)
Ending balance	8	5
Long- Term Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Ending balance	0	2
Net realized and unrealized gains (losses) included in earnings	1	(1)
Transfers out of Level 3		0
Settlements	0	0
Ending balance	1	1
Current Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(1)	0
Net realized and unrealized (losses) gains included in earnings	5	(2)
Transfers out of Level 3		0
Settlements	(7)	1
Ending balance	(3)	(1)
Long- Term Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(3)	(2)
Net realized and unrealized (losses) gains included in earnings	2	1
Transfers out of Level 3		0
Settlements	0	0
Ending balance	$ (1)	$ (1)

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Schedule of Leased Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease assets	$ 98	$ 107
Finance lease assets	21	25
Total right of use assets	119	132
Operating Lease, Liability, Current	23	24
Finance Lease, Liability, Current	3	3
Operating lease liabilities	83	88
Finance Lease, Liability, Noncurrent	21	22
Total lease liabilities	$ 130	$ 137

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Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Components Of Inventory [Line Items]
Total inventories	$ 26	$ 46
Natural Gas [Member]
Components Of Inventory [Line Items]
Total inventories	17	19
Natural Gas Liquids
Components Of Inventory [Line Items]
Total inventories	$ 9	$ 27

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Goodwill (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 0	$ 194	$ 159	$ 231
Goodwill, Written off Related to Sale of Business Unit	0	37
Goodwill, Impairment Loss, Net of Tax	159	0
Gathering and Processing
Goodwill [Line Items]
Goodwill	0	159	159	159
Goodwill, Written off Related to Sale of Business Unit	0	0
Goodwill, Impairment Loss, Net of Tax	159	0
Logistics and Marketing
Goodwill [Line Items]
Goodwill	0	35	$ 0	$ 72
Goodwill, Written off Related to Sale of Business Unit	0	37
Goodwill, Impairment Loss, Net of Tax	$ 0	$ 0

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Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 527	$ 421
Operating expenses	185	191
Net income	$ 341	$ 231

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Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Derivative [Line Items]
Trading and marketing (losses) gains, net	$ 152	$ (27)
Derivative Assets Not Designated As Hedging Instruments | Commodity derivatives
Derivative [Line Items]
Realized gains	18	27
Unrealized gains (losses)	134	(54)
Trading and marketing (losses) gains, net	$ 152	$ (27)

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Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Jul. 15, 2020	Jul. 01, 2020	Jun. 15, 2020	Jun. 01, 2020	May 15, 2020	May 01, 2020	Apr. 21, 2020	Mar. 16, 2020	Jan. 15, 2020	Dec. 16, 2019	Oct. 15, 2019	Sep. 16, 2019	Jul. 15, 2019	Jun. 17, 2019	Apr. 15, 2019	Mar. 15, 2019	Jan. 15, 2019	Apr. 13, 2020
Series A Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Preferred Limited Partnership Unit; Distribution Amount Declared										$ 36.875				$ 36.875
Series B Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Preferred Limited Partnership Unit; Distribution Amount Declared								$ 0.4922		$ 0.4922		$ 0.4922		$ 0.4922		$ 0.4922
Series C Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Preferred Limited Partnership Unit; Distribution Amount Declared									$ 0.4969		$ 0.4969		$ 0.4969		$ 0.4969		$ 0.5576
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit							$ 0.39
Distribution Made to Common Unitholders, Declaration Date							Apr. 21, 2020
Distribution Made to Limited Partner, Date of Record						May 01, 2020
Distribution Made to Limited Partner, Distribution Date					May 15, 2020
Restructuring and Related Cost, Number of Positions Eliminated, Inception to Date Percent																		15.00%
Restructuring and Related Cost, Expected Cost																		$ 11
Subsequent Event [Member] | Series A Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Preferred Limited Partner Distribution: Record Date			Jun. 01, 2020
Preferred Limited Partnership Distribution; Distribution Date			Jun. 15, 2020
Preferred Limited Partnership Unit; Distribution Amount Declared							$ 36.875
Subsequent Event [Member] | Series B Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Distribution Made to Common Unitholders, Declaration Date							Apr. 21, 2020
Preferred Limited Partner Distribution: Record Date				Jun. 01, 2020
Preferred Limited Partnership Distribution; Distribution Date			Jun. 15, 2020
Preferred Limited Partnership Unit; Distribution Amount Declared							$ 0.4922
Subsequent Event [Member] | Series C Preferred Limited Partners [Member]
Subsequent Event [Line Items]
Distribution Made to Common Unitholders, Declaration Date							Apr. 21, 2020
Preferred Limited Partner Distribution: Record Date		Jul. 01, 2020
Preferred Limited Partnership Distribution; Distribution Date	Jul. 15, 2020
Preferred Limited Partnership Unit; Distribution Amount Declared							$ 0.4969

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Commitments and Contingent Liabilities (Details)	3 Months Ended
	Mar. 31, 2020 USD ($)
Other Commitments [Line Items]
Administrative Settlement Penalty	$ 37,000
Amount Paid to Fund Supplemental Environmental Projects	149,000
New Mexico Environment Department Notice of Violation 1 [Member]
Other Commitments [Line Items]
Estimated Litigation Liability	150,000
New Mexico Environment Department Notice of Violation 2 [Member]
Other Commitments [Line Items]
Estimated Litigation Liability	142,000
Low end of estimate
Other Commitments [Line Items]
Estimated Litigation Liability	375,000
High end of estimate
Other Commitments [Line Items]
Estimated Litigation Liability	$ 460,000

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Risk Management and Hedging Activities - Additional Information (Detail) $ in Millions	Mar. 31, 2020 USD ($)
Derivative [Line Items]
Collateral, cash deposits	$ 35
Letters of credit received	$ 44

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Agreements and Transactions with Affiliates

3 Months Ended

Mar. 31, 2020

Related Party Transactions [Abstract]

Agreements and Transactions with Affiliates

. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

Under the Services and Employee Secondment Agreement (the “Services Agreement”), we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. The following table summarizes employee related costs that were charged by DCP Midstream, LLC to the Partnership that are included in the condensed consolidated statements of operations:

		Three Months Ended March 31,
		2020		2019
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense		$	44	$	49
General and administrative expense		$	35	$	47

Phillips 66 and its Affiliates

We sell a portion of our residue gas and NGLs to and purchase NGLs from Phillips 66 and its respective affiliates. We anticipate continuing to sell commodities to and purchase commodities from Phillips 66 and its affiliates in the ordinary course of business.

Unconsolidated Affiliates

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

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Three Months Ended March 31,
	2020		2019
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	212	$	326
Purchases and related costs from affiliates	$	27	$	31
Transportation and related costs from affiliates	$	23	$	14
Operating and maintenance and general administrative expenses	$	4	$	4
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	1	$	—
Purchases and related costs from affiliates	$	—	$	7
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	9	$	14
Transportation, processing, and other to affiliates	$	3	$	1
Purchases and related costs from affiliates	$	9	$	24
Transportation and related costs from affiliates	$	215	$	195

 We had balances with affiliates as follows:

	March 31, 2020		December 31, 2019
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	81	$	117
Accounts payable	$	27	$	20
Enbridge (including its affiliates):
Accounts payable	$	—	$	2
Unconsolidated affiliates:
Accounts receivable	$	17	$	21
Accounts payable	$	70	$	78

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Investments in Unconsolidated Affiliates

3 Months Ended

Mar. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	March 31, 2020		December 31, 2019
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,768	$	1,764
DCP Southern Hills Pipeline, LLC	66.67%	742		738
Front Range Pipeline LLC	33.33%	209		206
Gulf Coast Express LLC	25.00%	445		449
Texas Express Pipeline LLC	10.00%	100		101
Cheyenne Connector	50.00%	100		83
Mont Belvieu Enterprise Fractionator	12.50%	27		27
Mont Belvieu 1 Fractionator	20.00%	8		9
Discovery Producer Services LLC	40.00%	256		322
Panola Pipeline Company, LLC	15.00%	22		22
Other	Various	4		3
Total investments in unconsolidated affiliates		$	3,681	$	3,724

Earnings from investments in unconsolidated affiliates were as follows:

	Three Months Ended March 31,
	2020		2019
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	68
DCP Southern Hills Pipeline, LLC	20		23
Front Range Pipeline LLC	11		7
Gulf Coast Express LLC	16		—
Texas Express Pipeline LLC	4		5
Mont Belvieu Enterprise Fractionator	3		4
Mont Belvieu 1 Fractionator	3		4
Discovery Producer Services LLC (a)	(61)		—
Other	2		2
Total earnings from unconsolidated affiliates	$	76	$	113

(a)See Note 11 for further discussion

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

	Three Months Ended March 31,
	2020		2019
	(millions)
Statements of operations:
Operating revenue	$	527	$	421
Operating expenses	$	185	$	191
Net income	$	341	$	231

	March 31, 2020		December 31, 2019
	(millions)
Balance sheets:
Current assets	$	368	$	463
Long-term assets	7,598		7,546
Current liabilities	(169)		(231)
Long-term liabilities	(257)		(252)
Net assets	$	7,540	$	7,526

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Debt (Tables)

3 Months Ended

Mar. 31, 2020

Debt Disclosure [Abstract]

Schedule of Debt

	March 31, 2020		December 31, 2019
	(millions)
Senior notes:
Issued March 2010, interest at 5.350% payable semi-annually, due March 2020 (a)	$	—	$	600
Issued September 2011, interest at 4.750% payable semi-annually, due September 2021	500		500
Issued March 2012, interest at 4.950% payable semi-annually, due April 2022	350		350
Issued March 2013, interest at 3.875% payable semi-annually, due March 2023	500		500
Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025	825		825
Issued May 2019, interest at 5.125% payable semi-annually, due May 2029	600		600
Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)	300		300
Issued October 2006, interest at 6.450% payable semi-annually, due November 2036	300		300
Issued September 2007, interest at 6.750% payable semi-annually, due September 2037	450		450
Issued March 2014, interest at 5.600% payable semi-annually, due April 2044	400		400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043	550		550
Credit agreement:
Revolving credit facility, weighted-average variable interest rate of 2.157%, as of March 31, 2020, due December 2024	800		200
Accounts receivable securitization facility:
Accounts receivable securitization facility, weighted-average variable interest rate of 1.88% as of March 31, 2020, due August 2022	350		350
Fair value adjustments related to interest rate swap fair value hedges (a)	19		19
Unamortized issuance costs	(36)		(37)
Unamortized discount, net	(8)		(8)
Finance lease liabilities	24		25
Total debt	5,924		5,924
Current finance lease liabilities	3		3
Current debt	—		600
Total long-term debt	$	5,921	$	5,321

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

Future Maturities of Long-Term Debt

The maturities of our debt as of March 31, 2020 are as follows:

	Debt Maturities
	(millions)
2021	500
2022	700
2023	500
2024	800
Thereafter	3,425
Total debt	$	5,925

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Goodwill and Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2020

Goodwill Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

	As of March 31, 2020						As of March 31, 2019
	Gathering and Processing		Logistics and Marketing		Total		Gathering and Processing		Logistics and Marketing		Total
	(millions)
Balance, beginning of period	$	159	$	—	$	159	$	159	$	72	$	231
Impairment	(159)		—		(159)		—		—		—
Dispositions	—		—		—		—		(37)		(37)
Balance, end of period	$	—	$	—	$	—	$	159	$	35	$	194

Schedule of Finite-Lived Intangible Assets

	March 31,		December 31,
	2020		2019
	(millions)
Gross carrying amount	$	145	$	145
Accumulated amortization	(86)		(84)
Accumulated impairment	(11)		—
Intangible assets, net	$	48	$	61

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Contract Liabilities (Tables)

3 Months Ended

Mar. 31, 2020

Contract Assets and Liabilities [Abstract]

Contract with Customer, Asset and Liability [Table Text Block]

	March 31,
	2020
	(millions)
Balance, beginning of period	$	33
Additions	2
Revenue recognized (a)	(1)
Balance, end of period	$	34

(a) Deferred revenue recognized is included in transportation, processing and other on the condensed consolidated statement of operations.

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Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 368		$ 463
Long-term assets	7,598		7,546
Current liabilities	(169)		(231)
Long-term liabilities	(257)		(252)
Net assets	7,540		$ 7,526
Operating revenue	527	$ 421
Operating expenses	185	191
Net income	$ 341	$ 231

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Inventories - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Inventory Disclosure [Abstract]
Lower of cost or net realizable value adjustment	$ 4	$ 5

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Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 145		$ 145
Finite-Lived Intangible Assets, Accumulated Amortization	(86)		(84)
Impairment of Intangible Assets, Finite-lived	(11)	$ 0
Intangible assets, net	$ 48		$ 61

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Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Accumulated Other Comprehensive (Loss) Income	$ (7)		$ (7)
Trading and marketing gains (losses), net	152	$ (27)
Commodity derivatives | Derivative Assets Not Designated As Hedging Instruments
Derivative [Line Items]
Realized gains	18	27
Unrealized gains (losses)	134	(54)
Trading and marketing gains (losses), net	152	(27)
Accumulated Net Gain (Loss) from Cash Flow Hedges
Derivative [Line Items]
Accumulated Other Comprehensive (Loss) Income	(7)	(8)	(7)	$ (8)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Interest Rate Derivatives
Derivative [Line Items]
Accumulated Other Comprehensive (Loss) Income	(2)	(3)	(2)	(3)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Commodity derivatives
Derivative [Line Items]
Accumulated Other Comprehensive (Loss) Income	(6)	(6)	(6)	(6)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Foreign Currency Derivatives
Derivative [Line Items]
Accumulated Other Comprehensive (Loss) Income	1	$ 1	$ 1	$ 1
Cash Flow Hedging [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(1)
Cash Flow Hedging [Member] | Interest Rate Derivatives
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(1)
Cash Flow Hedging [Member] | Commodity derivatives
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	0
Cash Flow Hedging [Member] | Foreign Currency Derivatives
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 0

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Statement of Cash Flows, Supplemental Disclosures (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Item Effected [Line Items]
Cash paid for interest, net of amounts capitalized	$ 88	$ 65
Property, plant and equipment acquired with accounts payable and accrued liabilities	16	40
Right-of-Use Assets Obtained in Exchange for Operating and Finance Lease Liabilities	0	6
Accounting Standards Update 2016-02 [Member]
Item Effected [Line Items]
Cumulative Effect of Implementation of Topic 842	$ 0	$ 84

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income tax expense	$ 1	$ 1
Deferred income taxes	$ 30		$ 30

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Debt - Future Maturities of Long-Term Debt (Detail) $ in Millions	Mar. 31, 2020 USD ($)
Maturities of Long-term Debt [Abstract]
2021	$ 500
2022	700
2023	500
2024	800
Thereafter	3,425
Long Term Debt Maturities Repayments Of Principal Total	$ 5,925

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Inventories (Notes)

3 Months Ended

Mar. 31, 2020

Inventory Disclosure [Abstract]

Inventories

. Inventories

Inventories were as follows: 

	March 31, 2020		December 31, 2019
	(millions)
Natural gas	$	17	$	19
NGLs	9		27
Total inventories	$	26	$	46

We recognize lower of cost or net realizable value adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases and related costs in the condensed consolidated statements of operations. We recognized $4 million and $5 million of lower of cost or net realizable value adjustments during the three months ended March 31, 2020 and 2019, respectively.

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Fair Value Measurement (Notes)

3 Months Ended

Mar. 31, 2020

Fair Value Disclosures [Abstract]

Derivatives and Fair Value

11. Fair Value Measurement

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

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

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

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

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

Commodity Derivative Assets and Liabilities

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

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

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming online, 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.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, equity investments in unconsolidated affiliates, and intangible assets. 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 condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

During the three months ended March 31, 2020, it was determined that triggering events had occurred with respect to specific asset groups as a result of the impact of commodity prices on the respective recently prepared budget forecasts, coupled with a negative outlook for long-term production volume forecasts for these asset groups. As a result, we recognized a

$587 million impairment loss associated with certain asset groups in the Permian and South regions of our Gathering and Processing segment and an impairment of $61 million of our equity investment in Discovery Producer Services LLC (“Discovery”).

The $461 million impairment of certain gathering and processing assets in the Permian region was driven by the impact of the decrease of gas, NGL and condensate prices at March 31, 2020 on our forecasts for the assets. This assessment triggered an impairment analysis, and based on forecasted future undiscounted cash flows, management determined the carrying value of these asset groups were not fully recoverable. We used the income approach to calculate the fair value of the asset groups and compared it to the carrying value. The primary inputs were the forecasted future commodity pricing and the discount rate. The impairment amount recorded represented the difference between the fair and carrying values.

The $126 million impairment of certain gathering and processing assets in the South region was driven by a negative outlook for long-term gathering and processing volumes at more price sensitive assets as a result of decreased production forecasts. This revised outlook triggered an impairment analysis, and based on forecasted future undiscounted cash flows, management determined that the carrying value of these asset groups were not fully recoverable. We used the income approach to calculate the fair value of the asset group and compared it to the carrying value. The primary inputs to our calculation were forecasted future commodity pricing and the discount rate. The impairment amount recorded represented the difference between the fair and carrying values.

The $61 million impairment of Discovery was driven by market conditions that existed at March 31, 2020, which given the nature of the overall commodity price environment, the diminished probability of new well connects and projected volume decline, resulted in our determination that the decline in fair value was other than temporary. The estimate of fair value, which was based on an income approach, included assumptions such as future commodity prices from a combination of market pricing, investment bank research, ratings agencies, and industry outlooks, future cash flows based on our price and volume assumptions, terminal year multiple and discount rate. The impairment loss is included in earnings from unconsolidated affiliates in our condensed consolidated statement of operations.

We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets and investments that could result in future impairments. Such impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.

The following table presents the carrying value of certain assets and asset groups measured at fair value on a non-recurring basis, by condensed consolidated balance sheet caption as of and for the three months ended March 31, 2020.

	Fair Value Measurements Using Inputs Considered as
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
Long-lived assets	$	96	$	—	$	—	$	96	$	587
Goodwill	—		—		—		—		159
Direct investment in unconsolidated affiliate	256		—		—		256		61
Total impairments	$	352	$	—	$	—	$	352	$	807

The following table summarizes the significant unobservable inputs used in the valuation of certain assets and asset groups measured at fair value on a non-recurring basis as of March 31, 2020.

	March 31, 2020
Asset Groups	Valuation Techniques	Unobservable Inputs	Range (low-high) (a)	Average (b)
Long-lived assets, investment in unconsolidated affiliate, goodwill	Discounted cash flow	Oil prices	$34.52 - $67.61	$	55.98	Per barrel
		Natural gas prices	$2.28 - $4.12	$	3.35	Per MMBtu
		NGL prices	$0.30 - $0.62	$	0.52	Per gallon
		Discount rate	14%	14%
		Terminal value multiple	8x	8x
Goodwill	Market comparable companies	EBITDA multiple	5.2x - 16.5x	8x

(a)Commodity prices represent an average per year

(b)Represents the arithmetic average of the inputs and is not weighted by the relative fair value or volumetric amount.

The following table presents the financial instruments carried at fair value on a recurring basis as of March 31, 2020 and December 31, 2019, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:

	March 31, 2020								December 31, 2019
	Level 1		Level 2		Level 3		Total Carrying Value		Level 1		Level 2		Level 3		Total Carrying Value
	(millions)
Current assets:
Commodity derivatives	$	233	$	11	$	8	$	252	$	13	$	15	$	4	$	32
Long-term assets:
Commodity derivatives	$	47	$	5	$	1	$	53	$	1	$	1	$	—	$	2
Current liabilities:
Commodity derivatives	$	(169)	$	(20)	$	(3)	$	(192)	$	(15)	$	(42)	$	(1)	$	(58)
Long-term liabilities:
Commodity derivatives	$	(34)	$	(11)	$	(1)	$	(46)	$	(2)	$	(15)	$	(3)	$	(20)

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.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently

sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.

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

	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended March 31, 2020 (a):
Beginning balance	$	4	$	—	$	(1)	$	(3)
Net unrealized gains included in earnings	8		1		5		2
Settlements	(4)		—		(7)		—
Ending balance	$	8	$	1	$	(3)	$	(1)
Three months ended March 31, 2019 (a):
Beginning balance	$	14	$	2	$	—	$	(2)
Net unrealized (losses) gains included in earnings	(4)		(1)		(2)		1
Transfers out of Level 3	(2)		—		—		—
Settlements	(3)		—		1		—
Ending balance	$	5	$	1	$	(1)	$	(1)

(a)There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three months ended March 31, 2020 and 2019.

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

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

	March 31, 2020
Product Group	Fair Value		Valuation Techniques	Unobservable Input	Forward Curve Range	Weighted Average (a)
	(millions)
Assets
NGLs	$	9	Market approach	Longer dated forward curve prices	$0.11-$0.47	$0.33	Per gallon
Liabilities
NGLs	$	(3)	Market approach	Longer dated forward curve prices	$0.10-$0.53	$0.27	Per gallon
Natural gas	$	(1)	Market approach	Longer dated forward curve prices	$1.63-$2.50	$1.99	Per MMBtu

(a)Unobservable inputs were weighted by the instrument's notional amounts.

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 relationships with quoted market prices.

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 fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. The carrying value of borrowings under the Credit Agreement and the Securitization Facility approximate fair value as their interest rates are based on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of March 31, 2020 and December 31, 2019, the carrying value and fair value of our total debt, including current maturities, were as follows:

		March 31, 2020				December 31, 2019
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)
Total debt		$	5,936	$	4,252	$	5,936	$	6,130

(a) Excludes unamortized issuance costs and finance lease liabilities.

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2020

Property, Plant and Equipment [Abstract]

Classification of Property, Plant and Equipment

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

	Depreciable Life	March 31, 2020		December 31, 2019
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,677	$	8,406
Processing, storage and terminal facilities	35 — 60 Years	4,873		5,305
Other	3 — 30 Years	577		585
Finance lease assets	4 — 7 Years	21		25
Construction work in progress		194		183
Property, plant and equipment		13,342		14,504
Accumulated depreciation		(5,162)		(5,693)
Property, plant and equipment, net		$	8,180	$	8,811

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2020

Disaggregation of Revenue [Line Items]

Disaggregation of Revenue [Table Text Block]

We disaggregate our revenue from contracts with customers by type of contract for each of our reportable segments, as we believe it best depicts the nature, timing and uncertainty of our revenue and cash flows. The following tables set forth our revenue by those categories:

	Three Months Ended March 31, 2020
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	411	$	326	$	(290)	$	447
Sales of NGLs and condensate (a)	883		387		(324)		946
Transportation, processing and other	13		99		—		112
Trading and marketing gains, net (b)	51		101		—		152
Total operating revenues	$	1,358	$	913	$	(614)	$	1,657

	Three Months Ended March 31, 2019
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	637	$	557	$	(498)	$	696
Sales of NGLs and condensate (a)	1,403		648		(636)		1,415
Transportation, processing and other	12		103		—		115
Trading and marketing losses, net (b)	(7)		(20)		—		(27)
Total operating revenues	$	2,045	$	1,288	$	(1,134)	$	2,199

(a)   Includes $591 million and $858 million for the three months ended March 31, 2020 and 2019, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment, which are not within the scope of Topic 606.

(b)   Not within the scope of Topic 606.

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Leases (Tables)

3 Months Ended

Mar. 31, 2020

Leases [Abstract]

Schedule of Leasing Assets and Liabilities [Table Text Block]

	Location in Condensed Consolidated Balance Sheet	As of
		March 31, 2020		December 31, 2019
		(millions)
Assets
Operating lease assets	Operating lease assets	$	98	$	107
Finance lease assets	Property, plant and equipment	21		25
Total right of use assets		119		132
Liabilities
Current liabilities
Operating lease liabilities	Other current liabilities	$	23	$	24
Finance lease liabilities	Current debt	3		3
Noncurrent liabilities
Operating lease liabilities	Operating lease liabilities	$	83	$	88
Finance lease liabilities	Long-term debt	21		22
Total lease liabilities		$	130	$	137

Lease, Cost [Table Text Block]

	Location in Condensed Consolidated Statement of Operations	Three Months Ended March 31,
		2020		2019
		(millions)
Operating lease cost	Operating and maintenance expense	$	8	$	6
Variable lease cost	Operating and maintenance expense	2		2
Short term lease cost	Operating and maintenance expense	1		1
Total lease cost		$	11	$	9

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

	Future Minimum Lease Payments as of March 31, 2020
	Operating Leases		Finance Leases
	(millions)
2020 - remainder	$	20	$	4
2021	25		4
2022	22		4
2023	17		4
2024	9		3
Thereafter	29		8
Total lease payments	$	122	$	27
Less imputed interest	(16)		(3)
Total lease liabilities	$	106	$	24

Leases - Other Information

	Three Months Ended March 31,
	2020			2019
	(millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	7		$	6
Operating cash flows from finance leases	1			—
Right-of-use assets obtained in exchange for operating lease obligations:	$	—		$	6
Other information related to operating leases as follows:
Weighted average remaining lease term	6 years			6 years
Weighted average discount rate	4.00		%	4.00		%
Other information related to finance leases as follows:
Weighted average remaining lease term	6 years			—
Weighted average discount rate	3.00		%	—		%

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Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 18	$ 1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $3 and $3 million, respectively	485	726
Affiliates	98	138
Other	14	14
Inventories	26	46
Unrealized gains on derivative instruments	252	32
Collateral cash deposits	35	111
Other	30	12
Total current assets	958	1,080
Property, plant and equipment, net	8,180	8,811
Goodwill	0	159
Intangible assets, net	48	61
Investments in unconsolidated affiliates	3,681	3,724
Unrealized gains on derivative instruments	53	2
Operating lease assets	98	107
Other long-term assets	170	183
Total assets	13,188	14,127
Accounts payable:
Affiliates	97	100
Other	26	35
Current debt	3	603
Unrealized losses on derivative instruments	192	58
Accrued interest	67	80
Accrued taxes	69	65
Accrued wages and benefits	25	58
Capital spending accrual	10	28
Other	148	128
Total current liabilities	966	1,793
Long-term debt	5,921	5,321
Unrealized losses on derivative instruments	46	20
Deferred income taxes	30	30
Operating lease liabilities	83	88
Other long-term liabilities	226	242
Total liabilities	7,272	7,494
Equity:
Limited partners (208,329,928 and 143,317,328 common units authorized, issued and outstanding, respectively)	5,135	5,861
Accumulated other comprehensive loss	(7)	(7)
Total partners’ equity	5,888	6,605
Noncontrolling interests	28	28
Total equity	5,916	6,633
Total liabilities and equity	13,188	14,127
Allowance for Doubtful Accounts Receivable, Current	$ 2	3
Common unitholders, units outstanding (in shares)	208,329,928
Common unitholders, units issued (in shares)	208,329,928
Accounts Payable, Trade, Current	$ 329	638
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	41	1
Series A Preferred Limited Partners [Member]
Equity:
Preferred Units, Preferred Partners' Capital Accounts	498	489
Total equity	$ 498	$ 489
Preferred Units, Issued	500,000	500,000
Preferred Units, Outstanding	500,000	500,000
Series B Preferred Limited Partners [Member]
Equity:
Preferred Units, Preferred Partners' Capital Accounts	$ 156	$ 156
Total equity	$ 156	$ 156
Preferred Units, Issued	6,450,000	6,450,000
Preferred Units, Outstanding	6,450,000	6,450,000
Series C Preferred Limited Partners [Member]
Equity:
Preferred Units, Preferred Partners' Capital Accounts	$ 106	$ 106
Total equity	$ 106	$ 106
Preferred Units, Issued	4,400,000	4,400,000
Preferred Units, Outstanding	4,400,000	4,400,000

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
OPERATING ACTIVITIES:
Net (loss) income	$ (549)	$ 76
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	99	103
Earnings from unconsolidated affiliates	(76)	(113)
Distributions from unconsolidated affiliates	153	124
Net unrealized (gains) losses on derivative instruments	(134)	54
Loss on sale of assets, net	0	9
Asset Impairment	746	0
Other, net	(17)	(6)
Change in operating assets and liabilities, which (used) provided cash, net of effects of acquisitions:
Accounts receivable	(282)	(118)
Inventories	(16)	(14)
Accounts payable	(310)	29
Decrease in Other Operating Assets and Liabilities, Net	70	(103)
Net cash provided by operating activities	314	317
INVESTING ACTIVITIES:
Capital expenditures	(69)	(182)
Investments in unconsolidated affiliates	(34)	(131)
Proceeds from sale of assets	0	103
Net cash used in investing activities	(103)	(210)
FINANCING ACTIVITIES:
Proceeds from debt	2,151	1,402
Payments of debt	2,152	1,348
Distributions to preferred limited partners	5	5
Distributions to limited partners and general partner	(162)	(154)
Distributions to noncontrolling interest	1	1
Proceeds from (Payments for) Other Financing Activities	(2)	(1)
Net cash provided by (used in) financing activities	(171)	(107)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	40	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	41	1
Cash and cash equivalents, end of period	18	1
Restricted Cash, Current	12	0
Restricted Cash, Noncurrent	$ 11	$ 0

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Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies [Text Block]	The condensed consolidated financial statements have been prepared in accordance with GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could differ from these estimates, which may be significantly impacted by various factors, including those outside of our control, such as the impact of a sustained deterioration in commodity prices and volumes, which would negatively impact our results of operations, financial condition and cash flows.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy	Cash, Cash Equivalents, and Restricted Cash - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents. Restricted cash primarily consists of amounts held in our non-qualified deferred compensation plan. Restricted cash is excluded from cash and cash equivalents and is included in other current or non-current assets.

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Partnership Equity and Distributions (Notes)

3 Months Ended

Mar. 31, 2020

Equity [Abstract]

Partnership Equity and Distributions

Partnership Equity and Distributions Common Units — During the three months ended March 31, 2020 and 2019, we issued no common units, pursuant to our at-the-market program. As of March 31, 2020, $750 million of common units remained available for sale pursuant to our at-the-market program.

Distributions — During the first quarter of 2020, the board of directors of our general partner approved a plan to reduce quarterly distributions to our common unitholders by 50% to $0.39 per unit, beginning with the first quarter 2020 distribution, payable in May 2020. The following table presents our cash distributions paid in 2020 and 2019:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
February 14, 2020	$	0.78	$	162
November 14, 2019	$	0.78	$	155
August 14, 2019	$	0.78	$	154
May 15, 2019	$	0.78	$	155
February 14, 2019	$	0.78	$	154
Distributions to Series A Preferred unitholders
December 16, 2019	$	36.875	$	19
June 17, 2019	$	36.875	$	18
Distributions to Series B Preferred unitholders
March 16, 2020	$	0.4922	$	3
December 16, 2019	$	0.4922	$	4
September 16, 2019	$	0.4922	$	3
June 17, 2019	$	0.4922	$	3
March 15, 2019	$	0.4922	$	3
Distributions to Series C Preferred unitholders
January 15, 2020	$	0.4969	$	2
October 15, 2019	$	0.4969	$	2
July 15, 2019	$	0.4969	$	3
April 15, 2019	$	0.4969	$	2
January 15, 2019	$	0.5576	$	2

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Business Segments (Notes)

3 Months Ended

Mar. 31, 2020

Segment Reporting [Abstract]

Business Segments

Business Segments

Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 of the Notes to Consolidated Financial Statements in “Financial Statements and Supplementary Data” included as Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2019.

Our Logistics and Marketing segment includes transporting, trading, marketing, storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering condensate. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the Eliminations column.

The following tables set forth our segment information: 

Three Months Ended March 31, 2020: 

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	1,358	$	913	$	—	$	(614)	$	1,657
Gross margin (a)	$	111	$	400	$	—	$	—	$	511
Operating and maintenance expense	(7)		(142)		(4)		—		(153)
Depreciation and amortization expense	(3)		(89)		(7)		—		(99)
General and administrative expense	(2)		(3)		(51)		—		(56)
Asset impairments	—		(746)		—		—		(746)
Other expense, net	—		(3)		—		—		(3)
Earnings from unconsolidated affiliates	137		(61)		—		—		76
Interest expense	—		—		(78)		—		(78)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	236	$	(644)	$	(141)	$	—	$	(549)
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	236	$	(645)	$	(141)	$	—	$	(550)
Non-cash derivative mark-to-market (b)	$	42	$	92	$	—	$	—	$	134
Non-cash lower of cost or net realizable value adjustments	$	4	$	—	$	—	$	—	$	4
Capital expenditures	$	1	$	67	$	1	$	—	$	69
Investments in unconsolidated affiliates, net	$	34	$	—	$	—	$	—	$	34

Three Months Ended March 31, 2019:

	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	2,045	$	1,288	$	—	$	(1,134)	$	2,199
Gross margin (a)	$	58	$	337	$	—	$	—	$	395
Operating and maintenance expense	(9)		(165)		(4)		—		(178)
Depreciation and amortization expense	(3)		(93)		(7)		—		(103)
General and administrative expense	(3)		(6)		(58)		—		(67)
Other expense, net	—		(5)		—		—		(5)
Loss on sale of assets, net	(9)		—		—		—		(9)
Earnings from unconsolidated affiliates	113		—		—		—		113
Interest expense	—		—		(69)		—		(69)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	147	$	68	$	(139)	$	—	$	76
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	147	$	67	$	(139)	$	—	$	75
Non-cash derivative mark-to-market (b)	$	(18)	$	(36)	$	—	$	—	$	(54)
Non-cash lower of cost or net realizable value adjustments	$	5	$	—	$	—	$	—	$	5
Capital expenditures	$	14	$	165	$	3	$	—	$	182
Investments in unconsolidated affiliates, net	$	131	$	—	$	—	$	—	$	131

	March 31,		December 31,
	2020		2019
	(millions)
Segment long-term assets:
Gathering and Processing	$	8,101	$	8,904
Logistics and Marketing	3,861		3,848
Other (c)	268		295
Total long-term assets	12,230		13,047
Current assets	958		1,080
Total assets	$	13,188	$	14,127

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

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

(c)Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.

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Description of Business and Basis of Presentation - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2020
Investments in Greater Than 20%
Business Acquisition [Line Items]
Equity method ownership investment (as percent)	20.00%
Investments in Less Than 20%
Business Acquisition [Line Items]
Equity method ownership investment (as percent)	20.00%
DCP Midstream, LLC | DCP Midstream GP, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	100.00%
DCP Midstream, LLC | DCP Midstream LP
Business Acquisition [Line Items]
Ownership interest percentage by parent	57.00%
Phillips 66 | DCP Midstream, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%
Enbridge | DCP Midstream, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%

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Risk Management and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Gross and Net Amounts of Derivative Instruments

	March 31, 2020						December 31, 2019
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount		Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet		Amounts Not Offset in the Balance Sheet - Financial Instruments		Net Amount
	(millions)
Assets:
Commodity derivatives	$	305	$	—	$	305	$	34	$	—	$	34
Liabilities:
Commodity derivatives	$	(238)	$	—	$	(238)	$	(78)	$	—	$	(78)

Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value

The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2020 and December 31, 2019.

Balance Sheet Line Item	March 31, 2020		December 31, 2019		Balance Sheet Line Item	March 31, 2020		December 31, 2019
	(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	$	252	$	32	Unrealized losses on derivative instruments — current	$	(192)	$	(58)
Unrealized gains on derivative instruments — long-term	53		2		Unrealized losses on derivative instruments — long-term	(46)		(20)
Total	$	305	$	34	Total	$	(238)	$	(78)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2020:

	Interest Rate Cash Flow Hedges		Commodity Cash Flow Hedges		Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(2)	$	(6)	$	1	$	(7)
Net deferred (losses) gains in AOCI (ending balance)	$	(2)	$	(6)	$	1	$	(7)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1)	$	—	$	—	$	(1)

(a)Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2019:

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

(a)Relates to Discovery, an unconsolidated affiliate.

Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments

Commodity Derivatives: Statements of Operations Line Item		Three Months Ended March 31,
		2020		2019
	(millions)
Realized gains		$	18	$	27
Unrealized gains (losses)		134		(54)
Trading and marketing gains (losses), net		$	152	$	(27)

Schedule of Net Long or Short Positions Expected to be Realized

	March 31, 2020
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long Position (MMBtu)
2020	(1,410,000)	(27,659,800)	(25,009,803)	8,190,000
2021	(1,467,000)	(45,540,000)	(7,294,133)	4,325,000
2022	(107,000)	(13,687,500)	(104,842)	8,212,500
2023	—	—	—	7,300,000
2024	—	—	—	2,140,000
	March 31, 2019
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net Short Position (MMBtu)	Net Short Position (Bbls)	Net Long (Short) Position (MMBtu)
2019	(1,191,000)	(32,148,650)	(26,987,090)	2,102,500
2020	(283,000)	(930,000)	(14,388,830)	3,660,000
2021	(100,000)	—	(5,516,168)	(3,650,000)
2022	—	—	(175)	—

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Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Related Party Transaction [Line Items]
Operating and maintenance expense	$ 153	$ 178
Affiliated Entity | Phillips 66
Related Party Transaction [Line Items]
Purchases and related costs	27	31
Operating and maintenance expense	4	4
Natural Gas, NGLs and Condensate [Member] | Affiliated Entity | Unconsolidated Affiliates
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	9	14
Purchases and related costs	9	24
Natural Gas, NGLs and Condensate [Member] | Affiliated Entity | Phillips 66
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	212	326
Natural Gas, NGLs and Condensate [Member] | Affiliated Entity | Enbridge
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	1	0
Purchases and related costs	0	7
Transportation, Processing and Other [Member]
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	112	115
Transportation, Processing and Other [Member] | Affiliated Entity | Unconsolidated Affiliates
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	3	1
Purchases and related costs	215	195
Transportation, Processing and Other [Member] | Affiliated Entity | Phillips 66
Related Party Transaction [Line Items]
Purchases and related costs	$ 23	$ 14

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Schedule of Valuation Processes (Detail) $ in Millions	Mar. 31, 2020 USD ($) $ / gal
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Assets | $	$ 352
Level 3
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Assets | $	352
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Liabilities, fair value | $	$ (3)
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids | Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.10
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids | Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.53
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids | Weighted Average [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.27
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Liabilities, fair value | $	$ (1)
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas [Member] | Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	1.63
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas [Member] | Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	2.50
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas [Member] | Weighted Average [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	1.99
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Assets | $	$ 9
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids | Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.11
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids | Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.47
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids | Weighted Average [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.33

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Leases, Lease Cost (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Income and Expenses, Lessee [Abstract]
Operating Lease, Cost	$ 8	$ 6
Variable Lease, Cost	2	2
Short-term Lease, Cost	1	1
Lease, Cost	$ 11	$ 9