DCP Midstream, LP - Quarter Report: 2020 March (Form 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


¨			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

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.

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

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

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

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.

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

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

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%

Terminal value multiple

Goodwill

Market comparable companies

EBITDA multiple

5.2x - 16.5x

(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

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

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

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:

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		%	—		%

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.

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

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)

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.

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.

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.

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.

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

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.

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.

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

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.

•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 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.

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.

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

•$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

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.

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.

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.

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.

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.

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

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).

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.

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.”

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.

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

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:


		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.


		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.

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.

(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.

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.

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

$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

$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.

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

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.

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 20 16 Long-Term Incentive Plan.

10.2

Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream, LP 20 16 Long-Term Incentive Plan.

10.3

DCP Services, LLC Amended and Restated Executive Severance Plan effective February 19, 2020.

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.

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)