DCP Midstream, LP - Quarter Report: 2021 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, 2021


¨			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 April 30, 2021, there were 208,362,572 common units representing limited partnership interests outstanding.

DCP MIDSTREAM, LP

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2021

TABLE OF CONTENTS



Item		Page
	PART I. FINANCIAL INFORMATION
1	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2021 and December 31, 2020	2
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2021 and 2020	3
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2021 and 2020	4
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2021 and 2020	5
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2021	6
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2020	7
	Notes to the Condensed Consolidated Financial Statements	7
2	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
3	Quantitative and Qualitative Disclosures about Market Risk	47
4	Controls and Procedures	50
	PART II. OTHER INFORMATION
1	Legal Proceedings	50
1A.	Risk Factors	50

6	Exhibits	51
	Signatures	52

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						Credit Agreement governing our $1.4 billion unsecured revolving credit facility, 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
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, 2021, and in our Annual Report on Form 10-K for the year ended December 31, 2020, including the following risks and uncertainties:

•the impact resulting 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 Credit Agreement 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, including the impact of bankruptcies;

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

•industry changes, including 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, 2021		December 31, 2020
ASSETS	(millions)
Current assets:
Cash and cash equivalents	$	5	$	52


Accounts receivable:
Trade, net of allowance for credit losses of $2 and $2 million, respectively	725		572
Affiliates	321		238
Other	18		10
Inventories	30		38
Unrealized gains on derivative instruments	58		63

Collateral cash deposits	58		14
Other	16		21
Total current assets	1,231		1,008
Property, plant and equipment, net	7,913		7,993

Intangible assets, net	43		44
Investments in unconsolidated affiliates	3,640		3,641
Unrealized gains on derivative instruments	17		16
Operating lease assets	79		85
Other long-term assets	188		170
Total assets	$	13,111	$	12,957
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	669	$	536
Affiliates	199		161
Other	19		23

Current debt	504		505
Unrealized losses on derivative instruments	77		56
Accrued interest	71		85
Accrued taxes	68		59
Accrued wages and benefits	28		70
Capital spending accrual	2		4

Other	107		122
Total current liabilities	1,744		1,621
Long-term debt	5,178		5,119
Unrealized losses on derivative instruments	13		7
Deferred income taxes	30		30
Operating lease liabilities	71		76
Other long-term liabilities	243		243
Total liabilities	7,279		7,096
Commitments and contingent liabilities (see note 14)
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 (208,361,929 and 208,351,528 common units authorized, issued and outstanding, respectively)	5,052		5,090
Accumulated other comprehensive loss	(7)		(7)
Total partners’ equity	5,805		5,834
Noncontrolling interests	27		27
Total equity	5,832		5,861
Total liabilities and equity	$	13,111	$	12,957

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended March 31,
		2021		2020
		(millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	2,014	$	1,171
Sales of natural gas, NGLs and condensate to affiliates		555		222
Transportation, processing and other		118		112
Trading and marketing (losses) gains, net		(369)		152

Total operating revenues		2,318		1,657
Operating costs and expenses:
Purchases and related costs		1,763		872
Purchases and related costs from affiliates		55		36
Transportation and related costs from affiliates		219		238
Operating and maintenance expense		149		153
Depreciation and amortization expense		91		99
General and administrative expense		38		56

Asset impairments		—		746
Other expense, net		—		3


Total operating costs and expenses		2,315		2,203
Operating income (loss)		3		(546)

Earnings from unconsolidated affiliates		128		76
Interest expense, net		(77)		(78)
Income (loss) before income taxes		54		(548)
Income tax expense		—		(1)
Net income (loss)		54		(549)
Net income attributable to noncontrolling interests		(1)		(1)
Net income (loss) attributable to partners		53		(550)

Series A preferred limited partners' interest in net income		(9)		(9)
Series B preferred limited partners' interest in net income		(3)		(3)
Series C preferred limited partners' interest in net income		(2)		(2)

Net income (loss) allocable to limited partners		$	39	$	(564)
Net income (loss) per limited partner unit — basic and diluted		$	0.19	$	(2.71)

Weighted-average limited partner units outstanding — basic		208.4		208.3
Weighted-average limited partner units outstanding — diluted		208.5		208.3

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)


	Three Months Ended March 31,
		2021		2020
		(millions)
Net income (loss)		$	54	$	(549)
Other comprehensive income:


Total other comprehensive income		—		—
Total comprehensive income (loss)		54		(549)
Total comprehensive income attributable to noncontrolling interests		(1)		(1)
Total comprehensive income (loss) attributable to partners		$	53	$	(550)

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Three Months Ended March 31,
	2021		2020
	(millions)
OPERATING ACTIVITIES:
Net income (loss)	$	54	$	(549)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	91		99
Earnings from unconsolidated affiliates	(128)		(76)
Distributions from unconsolidated affiliates	129		153
Net unrealized losses (gains) on derivative instruments	53		(134)

Asset impairments	—		746


Other, net	2		17
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable	(245)		282
Inventories	8		16
Accounts payable	170		(310)



Other assets and liabilities	(138)		70
Net cash (used in) provided by operating activities	(4)		314
INVESTING ACTIVITIES:
Capital expenditures	(14)		(69)


Investments in unconsolidated affiliates	—		(34)



Net cash used in investing activities	(14)		(103)
FINANCING ACTIVITIES:
Proceeds from debt	1,143		2,151
Payments of debt	(1,086)		(2,152)






Distributions to preferred limited partners	(5)		(5)

Distributions to limited partners and general partner	(81)		(162)
Distributions to noncontrolling interests	(1)		(1)



Other	—		(2)
Net cash used in financing activities	(30)		(171)
Net change in cash, cash equivalents and restricted cash	(48)		40
Cash, cash equivalents and restricted cash, beginning of period	56		1
Cash, cash equivalents and restricted cash, end of period	$	8	$	41

Reconciliation of cash, cash equivalents, and restricted cash:	March 31, 2021		March 31, 2020
Cash and cash equivalents	$	5	$	18
Restricted cash included in other current assets	3		12
Restricted cash included in other long-term assets	—		11
Total cash, cash equivalents, and restricted cash	$	8	$	41

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, 2021		$	489	$	156	$	106	$	5,090	$	(7)	$	27	$	5,861
Net income		9		3		2		39		—		1		54






Distributions to unitholders		—		(3)		(2)		(81)		—		—		(86)
Distributions to noncontrolling interests		—		—		—		—		—		(1)		(1)
Equity based compensation		—		—		—		4		—		—		4

Balance, March 31, 2021		$	498	$	156	$	106	$	5,052	$	(7)	$	27	$	5,832

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)


	Partner's 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(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 1 5 - 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, 2021, 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, 2021 are not necessarily indicative of the results that may be expected for the year ending December 31, 2021. 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 2020 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020.

2. 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, 2021
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	1,120	$	628	$	(508)	$	1,240
Sales of NGLs and condensate (a)	1,205		710		(586)		1,329
Transportation, processing and other	14		104		—		118
Trading and marketing losses, net (b)	(241)		(128)		—		(369)
Total operating revenues	$	2,098	$	1,314	$	(1,094)	$	2,318

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

(a) Includes $414 million of revenues for the three months ended March 31, 2021, from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment, which is net of $390 million of buy-sell purchases related to buy-sell revenues of $444 million which are not within the scope of FASB ASU 2014-09 "Revenue from Contractors with Customer" ("Topic 606").

(b) Not within the scope of Topic 606.


	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

(a) Includes $591 million for the three months ended March 31, 2020 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 $338 million as of March 31, 2021. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to be recognized through 2030 with a weighted average remaining life of four years as of March 31, 2021. 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.

3. 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.

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


	March 31,
	2021
	(millions)
Balance, beginning of period	$	35


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, 2021.

4. 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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

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,
			2021		2020
		(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense			$	39	$	44
General and administrative expense			$	26	$	35

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.

Enbridge and its Affiliates

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

Unconsolidated Affiliates

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

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:


	Three Months Ended March 31,
		2021		2020
		(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates		$	527	$	212
Purchases and related costs from affiliates		$	30	$	27
Transportation and related costs from affiliates		$	37	$	23
Operating and maintenance and general administrative expenses		$	2	$	4
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates		$	4	$	1
Purchases and related costs from affiliates		$	7	$	—


Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates		$	24	$	9
Transportation, processing, and other to affiliates		$	5	$	3
Purchases and related costs from affiliates		$	18	$	9
Transportation and related costs from affiliates		$	182	$	215

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

We had balances with affiliates as follows:


	March 31, 2021		December 31, 2020
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	297	$	217
Accounts payable	$	116	$	89
Other assets	$	—	$	1
Enbridge (including its affiliates):
Accounts receivable	$	4	$	—
Accounts payable	$	3	$	2


Unconsolidated affiliates:
Accounts receivable	$	20	$	21
Accounts payable	$	80	$	70

5. Inventories

Inventories were as follows:


	March 31, 2021		December 31, 2020
	(millions)
Natural gas	$	12	$	18
NGLs	18		20
Total inventories	$	30	$	38

We recognize lower of cost or net realizable value adjustments when the carrying value of our inventories exceeds their net realizable value. These non-cash charges are a component of purchases and related costs in the condensed consolidated statements of operations. We recognized no lower of cost or net realizable value adjustments during the three months ended March 31, 2021. We recognized $4 million of lower of cost or net realizable value adjustments for the three months ended March 31, 2020.

6. Property, Plant and Equipment

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


	Depreciable Life	March 31, 2021		December 31, 2020
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,689	$	7,680
Processing, storage and terminal facilities	35 — 60 Years	4,992		4,986
Other	3 — 30 Years	582		585
Finance lease assets	3 — 6 Years	25		25
Construction work in progress		137		144
Property, plant and equipment		13,425		13,420
Accumulated depreciation		(5,512)		(5,427)
Property, plant and equipment, net		$	7,913	$	7,993

We had no capitalized interest on construction projects for the three months ended March 31, 2021. Capitalized interest on construction projects was $2 million for the three months ended March 31, 2020.

Depreciation expense was $90 million and $97 million for the three months ended March 31, 2021 and 2020, respectively.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

7. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:


		Carrying Value as of
	Percentage Ownership	March 31, 2021		December 31, 2020
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,733	$	1,723
DCP Southern Hills Pipeline, LLC	66.67%	733		734
Gulf Coast Express LLC	25.00%	432		436
Front Range Pipeline LLC	33.33%	195		198
Texas Express Pipeline LLC	10.00%	96		97
Discovery Producer Services LLC	40.00%	243		244
Mont Belvieu 1 Fractionator	20.00%	6		7
Mont Belvieu Enterprise Fractionator	12.50%	27		26
Cheyenne Connector, LLC	50.00%	151		152
Panola Pipeline Company, LLC	15.00%	21		21
Other	Various	3		3
Total investments in unconsolidated affiliates		$	3,640	$	3,641

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended March 31,
			2021		2020
		(millions)
DCP Sand Hills Pipeline, LLC			$	62	$	78
DCP Southern Hills Pipeline, LLC			24		20
Gulf Coast Express LLC			15		16
Front Range Pipeline LLC			9		11
Texas Express Pipeline LLC			4		4
Discovery Producer Services LLC (a)			8		(61)
Mont Belvieu 1 Fractionator			2		3
Mont Belvieu Enterprise Fractionator			1		3
Cheyenne Connector, LLC			3		—
Other			—		2
Total earnings from unconsolidated affiliates			$	128	$	76

(a) In 2020, we recognized an impairment of $61 million on our equity investment in Discovery Producer Services LLC.

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


	Three Months Ended March 31,
			2021		2020
		(millions)
Statements of operations:
Operating revenue			$	489	$	527
Operating expenses			$	190	$	185
Net income			$	298	$	341

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)


	March 31, 2021		December 31, 2020
	(millions)
Balance sheets:
Current assets	$	368	$	355
Long-term assets	7,446		7,510
Current liabilities	(163)		(177)
Long-term liabilities	(260)		(258)
Net assets	$	7,391	$	7,430

8. Fair Value Measurement

Valuation Hierarchy

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

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

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

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

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

Commodity Derivative Assets and Liabilities

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

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

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

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, 2021 we determined there were no impairments associated with any of our asset groups. During the three months ended March 31, 2020, we recognized a $587 million impairment loss associated with certain asset groups in the Permian and South regions of our Gathering and Processing segment and an impairment of $61 million of our equity investment in Discovery Producer Services LLC (“Discovery”).

The following table presents the financial instruments carried at fair value on a recurring basis as of March 31, 2021 and December 31, 2020, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:


	March 31, 2021								December 31, 2020
	Level 1		Level 2		Level 3		Total Carrying Value		Level 1		Level 2		Level 3		Total Carrying Value
	(millions)
Current assets:
Commodity derivatives	$	21	$	37	$	—	$	58	$	21	$	42	$	—	$	63
Short-term investments	$	1	$	1	$	—	$	2	$	—	$	—	$	—	$	—

Long-term assets:
Commodity derivatives	$	4	$	11	$	2	$	17	$	1	$	13	$	2	$	16
Investments in marketable securities (a)	$	25	$	—	$	—	$	25	$	22	$	1	$	—	$	23
Current liabilities:
Commodity derivatives	$	(41)	$	(32)	$	(4)	$	(77)	$	(19)	$	(34)	$	(3)	$	(56)

Long-term liabilities:
Commodity derivatives	$	(5)	$	(7)	$	(1)	$	(13)	$	—	$	(6)	$	(1)	$	(7)

(a) $2 million and $4 million recorded within "other" current asset and $25 million and $19 million recorded within "Other long term assets" as of March 31, 2021 and December 31, 2020, respectfully.

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.

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


	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended March 31, 2021 (a):
Beginning balance	$	—	$	2	$	(3)	$	(1)
Net unrealized losses included in earnings	—		—		(5)		—


Settlements	—		—		4		—


Ending balance	$	—	$	2	$	(4)	$	(1)
Net unrealized losses on derivatives still held included in earnings	$	—	$	—	$	(3)	$	—
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)
Net unrealized gains (losses) on derivatives still held included in earnings	$	7	$	—	$	(2)	$	2

(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three months ended March 31, 2021 and 2020.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

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, 2021

Product Group

Fair Value

Valuation Techniques

Unobservable Input

Forward
Curve Range

Weighted Average (a)

(millions)

Assets

Natural gas

Market approach

Longer dated forward curve prices

$1.85-$2.74

$2.25

Per MMBtu

Liabilities

NGLs

(4)

Market approach

Longer dated forward curve prices

$0.22-$1.32

$0.61

Per gallon

Natural gas

(1)

Market approach

Longer dated forward curve prices

$1.85-$2.86

$2.25

Per MMBtu

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

Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationships with quoted market prices.

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.

We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. The carrying value of borrowings under the Credit Agreement and the Securitization Facility approximate fair value as their interest rates are based on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of March 31, 2021 and December 31, 2020, the carrying value and fair value of our total debt, including current maturities, were as follows:


		March 31, 2021				December 31, 2020
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)

Total debt		$	5,693	$	5,992	$	5,635	$	5,938

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

9. Leases

We have operating leases for transportation agreements, office space, 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 20 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:

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)


	Location in Condensed Consolidated Balance Sheet	As of
		March 31, 2021		December 31, 2020
		(millions)
Assets
Operating lease assets	Operating lease assets	$	79	$	85
Finance lease assets	Property, plant and equipment	25		25
Total right of use assets		$	104	$	110

Liabilities
Current liabilities
Operating lease liabilities	Other current liabilities	$	23	$	24
Finance lease liabilities	Current debt	4		5
Noncurrent liabilities
Operating lease liabilities	Operating lease liabilities	$	71	$	76
Finance lease liabilities	Long-term debt	21		22
Total lease liabilities		$	119	$	127

Variable lease costs primarily consist of common area maintenance on our office spaces and variable transportation costs. The components of lease expense are as follows:


	Location in Condensed Consolidated Statement of Operations	Three Months Ended March 31,
				2021		2020
			(millions)
Operating lease cost	Operating and maintenance expense			$	7	$	8
Finance lease cost
Amortization of right of use assets	Depreciation and amortization expense			1		—

Variable lease cost	Operating and maintenance expense			1		2
Short term lease cost	Operating and maintenance expense			1		1
Total lease cost				$	10	$	11

Maturities of operating and finance lease liabilities under non-cancelable leases as of March 31, 2021 are as follows:


	Future Minimum Lease Payments as of March 31, 2021
	Operating Leases		Finance Leases
	(millions)
2021 - remainder	$	20	$	4
2022	24		5
2023	19		5
2024	12		6
2025	8		2
Thereafter	23		9
Total lease payments	$	106	$	31
Less imputed interest	(12)		(6)
Total lease liabilities	$	94	$	25

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

Supplemental cash flow information related to leases is as follows:


	Three Months Ended March 31,
	2021			2020
	(millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	8		$	7
Operating cash flows from finance leases	1			1




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	5 years			6 years
Weighted average discount rate	3.00		%	3.00		%

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

10. Debt


	March 31, 2021		December 31, 2020
	(millions)




Senior notes:




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 June 2020, interest at 5.625% payable semi-annually, due July 2027	500		500
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, variable interest rate of 1.470% as of March 31, 2021, due December 2024	58		—
Accounts receivable securitization facility:
Accounts receivable securitization facility, interest at 1.010% as of March 31, 2021, due August 2022	350		350
Fair value adjustments related to interest rate swap fair value hedges (a)	17		17
Unamortized issuance costs	(36)		(38)
Unamortized discount, net	(7)		(7)
Finance lease liabilities	25		27
Total debt	5,682		5,624
Current finance lease liabilities	4		5
Current debt	500		500
Total long-term debt	$	5,178	$	5,119

(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 date 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, 2021 and 2020

(unaudited)

Credit Agreement

We are a party to a $1.4 billion unsecured revolving credit facility governed by the 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, 2021, we had unused borrowing capacity of $1,332 million, net of $58 million of outstanding borrowings and $10 million of letters of credit, under the Credit Agreement, of which at least $1,123 million would have been available to borrow for working capital and other general partnership purposes based on the financial covenants set forth in the Credit Agreement. 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, 2021, DCP Receivables had $797 million of our accounts receivable securing borrowings of $350 million under the Securitization Facility.

The maturities of our debt as of March 31, 2021 are as follows:


	Debt Maturities
	(millions)
2021	$	500
2022	700
2023	500
2024	58
2025	825
Thereafter	3,100
Total debt	$	5,683

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

11. 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, 2021, we had cash deposits of $58 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of March 31, 2021, we held letters of credit of $107 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, 2021						December 31, 2020
	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	$	75	$	—	$	75	$	79	$	—	$	79

Liabilities:
Commodity derivatives	$	(90)	$	—	$	(90)	$	(63)	$	—	$	(63)

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(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, 2021 and December 31, 2020.


Balance Sheet Line Item	March 31, 2021		December 31, 2020		Balance Sheet Line Item	March 31, 2021		December 31, 2020
	(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	$	58	$	63	Unrealized losses on derivative instruments — current	$	(77)	$	(56)
Unrealized gains on derivative instruments — long-term	17		16		Unrealized losses on derivative instruments — long-term	(13)		(7)
Total	$	75	$	79	Total	$	(90)	$	(63)

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, 2021:


	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)
Losses reclassified from AOCI to earnings — effective portion	—		—		—		—
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	$	—	$	—	$	—	$	—

(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, 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)
Losses reclassified from AOCI to earnings — effective portion	—		—		—		—
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.

For the three months ended March 31, 2021 and 2020, 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, 2021 and 2020, 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, 2021 and 2020

(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,
		2021		2020
		(millions)
Realized (losses) gains		$	(316)	$	18
Unrealized (losses) gains		(53)		134
Trading and marketing (losses) gains, net		$	(369)	$	152

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, 2021
	Crude Oil	Natural Gas	Natural Gas Liquids	Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)	Net (Short) Long Position (MMBtu)	Net Short Position (Bbls)	Net (Short) Long Position (MMBtu)
2021	(1,579,000)	(52,409,500)	(9,599,728)	(11,595,000)
2022	(579,000)	(32,850,000)	(2,350,342)	—
2023	(43,000)	7,300,000	(1,320,000)	4,720,000
2024	—	—	(1,440,000)	4,885,000
2025	—	—	(1,440,000)	1,825,000
2026	—	—	(240,000)	—

	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

12. Partnership Equity and Distributions

Common Units — During the three months ended March 31, 2021 and 2020, we issued no common units pursuant to our at-the-market program. As of March 31, 2021, $750 million of common units remained available for sale pursuant to our at-the-market program.

Our general partner is entitled to a percentage of all quarterly distributions equal to its limited partner interest, together with DCP Midstream, LLC, of approximately 57% as of March 31, 2021.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

Distributions — The following table presents our cash distributions paid in 2021 and 2020:


Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
February 12, 2021	$	0.39	$	81
November 13, 2020	$	0.39	$	81
August 14, 2020	$	0.39	$	82
May 15, 2020	$	0.39	$	81
February 14, 2020	$	0.78	$	162










Distributions to Series A Preferred unitholders
December 15, 2020	$	36.8750	$	19
June 15, 2020	$	36.8750	$	18





Distributions to Series B Preferred unitholders
March 15, 2021	$	0.4922	$	3
December 15, 2020	$	0.4922	$	4
September 15, 2020	$	0.4922	$	3
June 15, 2020	$	0.4922	$	3
March 16, 2020	$	0.4922	$	3







Distributions to Series C Preferred unitholders
January 15, 2021	$	0.4969	$	2
October 15, 2020	$	0.4969	$	2
July 15, 2020	$	0.4969	$	3
April 15, 2020	$	0.4969	$	2
January 15, 2020	$	0.4969	$	2

13. Net Income or Loss per Limited Partner Unit

We have the ability to elect to settle restricted phantom units at our discretion in either cash or common units. For restricted phantom units granted during 2021 and 2020, we have the ability and intent to settle vested units through the issuance of common units. There were 350,820 restricted phantom units outstanding as of March 31, 2020 that were not included in the calculation of diluted net loss per unit because including them would have been anti-dilutive.

Basic and diluted net income per limited partner unit was calculated as follows for the three months ended March 31, 2021 and 2020, respectively.


	Three Months Ended March 31,
			2021		2020
		(millions, except per unit amounts)

Net income (loss) attributable to limited partners			$	39	$	(564)
Weighted average limited partner units outstanding, basic			208,359,725		208,329,928

Weighted average limited partner units outstanding, diluted			208,461,526		208,329,928
Net income (loss) per limited partner unit, basic and diluted			$	0.19	$	(2.71)

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

14. Commitments and Contingent Liabilities

Litigation — We are not a party to any material 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.

Environment, Health and Safety — 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 the environment, health and safety. 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 health and safety, public health and 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, health and safety standards applicable to workers and the public, 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 as a party under federal, state, and local laws regulating the discharge of materials into the environment. We have elected to disclose matters where we reasonably believe such proceeding would result in monetary sanctions, exclusive of interest and costs, of $1.0 million or more. 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 on our results of operations, financial position, or cash flows:

•In August 2020, the New Mexico Environment Department ("NMED") issued an Administrative Compliance Order (the “August ACO”) alleging that emissions at four of our natural gas processing plants exceeded respective air permit limits or requirements during various instances of what we reported were facility upsets, malfunctions, startups or shutdowns from May of 2017 through August 2018, and asserting an administrative civil penalty of approximately $3.3 million for those emissions events during the stated period of time. We have challenged the allegations and asserted penalties in the August ACO based on legal limitations, including that emissions that exceed permit limits or requirements due to facility upset, malfunction, startup, and shutdown events are not subject to civil penalties under New Mexico law. We formally responded to the August ACO and will engage in information exchanges and discussions with NMED about the propriety of the allegations and asserted penalties, and the matter may go to hearing.

•In June 2020, NMED issued an Administrative Compliance Order (the “June ACO”) alleging that emissions at several of our field compression sites exceeded respective air permit limits or requirements during various instances of what we reported were facility upsets, malfunctions, startups or shutdowns from 2018 through the first half of 2019. The June ACO asserts an administrative civil penalty of approximately $5.3 million. We have challenged the allegations and asserted penalties based on legal limitations, including that emissions that exceed permit limits or requirements due to facility upset, malfunction, startup, and shutdown events are not subject to civil penalties under New Mexico

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

law. We formally responded to the June ACO and will engage in information exchanges and discussions with NMED about the propriety of the allegations and asserted penalties, and the matter may go to hearing.

•In March 2019, Region 8 of the U.S. Environmental Protection Agency (“EPA”) issued a Notice of Violation alleging various non-compliance with federal Leak Detection and Repair regulations, known as Subparts KKK and OOOO that exist to mitigate emissions of volatile organic compounds from certain equipment at natural gas plants, at various times over the course of late 2011 through 2017 at five of our Colorado natural gas processing plants. DCP does not agree with many of the allegations of non-compliance. DCP has been and is engaging in information exchanges and discussions with EPA about the propriety of the allegations, including the facts and regulatory underpinnings of the various allegations. DCP’s recent discussions with EPA include the possibility of resolving the allegations, including potential civil penalties and other elements, although this matter may end up in formal proceedings. EPA may require a civil penalty or equivalent that is larger than the disclosure threshold amount described above, although we do not believe that the result of this matter would have a material adverse effect on our results of operations, financial position, or cash flows.

15. 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. Adjusted 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 the 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, 2020.

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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

The following tables set forth our segment information:

Three Months Ended March 31, 2021:


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	2,098	$	1,314	$	—	$	(1,094)	$	2,318
Adjusted gross margin (a)	$	36	$	245	$	—	$	—	$	281
Operating and maintenance expense	(6)		(140)		(3)		—		(149)
General and administrative expense	(1)		(4)		(33)		—		(38)
Depreciation and amortization expense	(3)		(81)		(7)		—		(91)





Earnings from unconsolidated affiliates	120		8		—		—		128
Interest expense	—		—		(77)		—		(77)

Net income (loss)	$	146	$	28	$	(120)	$	—	$	54
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	146	$	27	$	(120)	$	—	$	53
Non-cash derivative mark-to-market	$	(5)	$	(48)	$	—	$	—	$	(53)

Capital expenditures	$	—	$	13	$	1	$	—	$	14

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
Adjusted gross margin (a)	$	111	$	400	$	—	$	—	$	511
Operating and maintenance expense	(7)		(142)		(4)		—		(153)
General and administrative expense	(2)		(3)		(51)		—		(56)
Depreciation and amortization expense	(3)		(89)		(7)		—		(99)
Asset impairments	—		(746)		—		—		(746)
Other expense, net	—		(3)		—		—		(3)



Earnings (loss) 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	$	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


	March 31,		December 31,
	2021		2020
	(millions)
Segment long-term assets:
Gathering and Processing	$	7,718	$	7,788
Logistics and Marketing	3,938		3,929
Other (b)	224		232
Total long-term assets	11,880		11,949
Current assets	1,231		1,008
Total assets	$	13,111	$	12,957

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2021 and 2020

(unaudited)

(a) Adjusted gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Adjusted 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, adjusted gross margin should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or gross margin as determined in accordance with GAAP. Our adjusted gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate adjusted gross margin in the same manner.

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

16. Supplemental Cash Flow Information


	Three Months Ended March 31,
	2021		2020
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	89	$	88

Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	4	$	16
Other non-cash changes in property, plant and equipment	$	(2)	$	—

17. Subsequent Events

On April 20, 2021, 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 14, 2021 to unitholders of record on April 30, 2021.

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, 2021 to unitholders of record on June 1, 2021.

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, 2021 to unitholders of record on June 1, 2021. The Series C distribution will be paid on July 15, 2021 to unitholders of record on July 1, 2021.

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, 2020.

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

The COVID-19 pandemic, continued to disrupt the U.S. economy causing reduced demand for gas and NGLs that materially and adversely affect our business, results of operations and liquidity. Additionally, in February 2021, the U.S. experienced Winter Storm Uri, bringing extreme cold temperatures, ice, and snow to the central U.S. that adversely impacted producer volumes, substantially disrupted regional gas market prices and temporarily disrupted the operations of some the Company’s assets in the Permian, South and Midcontinent Regions. The extent of the impact of Winter Storm Uri and COVID-19 pandemic on our operational and financial performance is anticipated to be temporary, but there is uncertainty around the extent and duration of the COVID-19 pandemic and its related impact on us. Management anticipates that our results of operations will continue to be negatively affected by the industry and economic impact of the COVID-19 pandemic in 2021 and possibly beyond, however, 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.

Our business is impacted by commodity prices and volumes. We mitigate a significant portion of commodity price risk on an overall Partnership basis through 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 recovered since the start of the pandemic, however demand and production remain limited and our natural gas throughput and NGL volumes continue to be impacted.

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, more heavily focused on the business of the Logistics and Marketing segment 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 impacted by, among other things, reduced drilling activity, depressed commodity prices, severe weather disruptions, operational outages and ethane rejection. Upstream producers have reduced capital expenditures in response to COVID-19 demand decreases and are maintaining this reduction as uncertainty continues into 2021. As a result, we expect volumes to remain below 2019 levels which will to continue to impact earnings.

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. During February 2021, Winter Storm Uri resulted in lower volumes and abnormally high gas prices. Certain counterparty billings during this time are under dispute and may take longer to collect than normal.

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

•We have focused cost reduction efforts.

•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 2021, our strategic objectives are to generate Excess Free Cash Flows (a non-GAAP measure defined in “Reconciliation of Non-GAAP Measures - Excess Free Cash Flows”) and reduce leverage. We believe the key elements to generating Excess Free 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 Excess Free Cash Flows. We will continue to pursue incremental revenue, cost efficiencies and operating improvements of our assets through process and technology improvements.

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.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2021 plan includes sustaining capital expenditures of between $45 million and $85 million and expansion capital expenditures of between $25 million and $75 million.

Recent Events

Common and Preferred Distributions

Results of Operations

Consolidated Overview

The following table and discussion provides a summary of our consolidated results of operations for the three months ended March 31, 2021 and 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three Months Ended March 31,						Variance 2021 vs. 2020
			2021		2020			Increase (Decrease)		Percent
		(millions, except operating data)
Operating revenues (a):
Logistics and Marketing			$	2,098	$	1,358		$	740	54	%
Gathering and Processing			1,314		913			401		44	%
Inter-segment eliminations			(1,094)		(614)			480		78	%
Total operating revenues			2,318		1,657			661		40	%
Purchases and related costs
Logistics and Marketing			(2,062)		(1,247)			815		65	%
Gathering and Processing			(1,069)		(513)			556		*
Inter-segment eliminations			1,094		614			480		78	%
Total purchases			(2,037)		(1,146)			891		78	%
Operating and maintenance expense			(149)		(153)			(4)		(3	%)
Depreciation and amortization expense			(91)		(99)			(8)		(8	%)
General and administrative expense			(38)		(56)			(18)		(32	%)
Asset impairments			—		(746)			(746)		*
Other expense, net			—		(3)			(3)		*



Earnings from unconsolidated affiliates			128		76			52		68	%
Interest expense			(77)		(78)			(1)		(1	%)
Income tax expense			—		(1)			(1)		*
Net income attributable to noncontrolling interests			(1)		(1)			—		—	%
Net income (loss) attributable to partners			$	53	$	(550)		$	603	*
Other data:
Adjusted gross margin (b):
Logistics and Marketing			$	36	$	111		$	(75)	(68	%)
Gathering and Processing			245		400			(155)		(39	%)
Total adjusted gross margin			$	281	$	511		$	(230)	(45	%)

Non-cash commodity derivative mark-to-market			$	(53)	$	134		$	(187)	*
NGL pipelines throughput (MBbls/d) (c)			578		677			(99)		(15	%)
Gas pipelines throughput (TBtu/d) (c)			1.0		0.80			0.20		25	%
Natural gas wellhead (MMcf/d) (c)			4,077		4,940			(863)		(17	%)
NGL gross production (MBbls/d) (c)			361		404			(43)		(11	%)

* Percentage change is not meaningful.

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

(b) Adjusted gross margin consists of total operating revenues less purchases and related costs. Segment adjusted 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”.

(c) 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, 2021 vs. Three Months Ended March 31, 2020

Total Operating Revenues — Total operating revenues increased $661 million in 2021 compared to 2020, primarily as a result of the following:

•$740 million increase for our Logistics and Marketing segment, primarily due to higher commodity prices and an increase in transportation, processing and other, partially offset by lower NGL and gas sales volumes and unfavorable commodity derivative activity; and

•$401 million increase for our Gathering and Processing segment, primarily due to higher commodity prices and an increase in transportation, processing and other, partially offset by unfavorable commodity derivative activity and decreased volumes in all regions.

These increases were partially offset by:

•$480 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 higher commodity prices, partially offset by lower NGL and gas sales volumes.

Total Purchases — Total purchases increased $891 million in 2021 compared to 2020, primarily as a result of the following:

•$815 million increase for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$556 million increase for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These increases were partially offset by:

•$480 million change in inter-segment eliminations, for the reasons discussed above.

General and Administrative Expense — General and administrative expense decreased in 2021 compared to 2020, primarily as a result of reduced headcount and employee benefits.

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

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2021 compared to 2020, primarily as a result of an impairment in our equity investment in Discovery in 2020, partially offset by decline of volumes from third party production on the Sand Hills pipeline in 2021.

Net Income (Loss) Attributable to Partners — Net income (loss) attributable to partners increased in 2021 compared to 2020 for the reasons discussed above.

Adjusted Gross Margin — Adjusted gross margin decreased $230 million in 2021 compared to 2020, primarily as a result of the following:

•$155 million decrease for our Gathering and Processing segment, primarily as a result of unfavorable commodity derivative activity attributable to our corporate equity hedge program, lower base volumes and margins in the South, Permian, and Midcontinent, lower margins in the DJ Basin due to offload processing fees and the negative impact of Winter Storm Uri resulting in producer shut-ins, unfavorable commodity derivative activity associated with swaps and reduced producer payments and marketing activity, partially offset by higher commodity pricing; and

•$75 million decrease for our Logistics and Marketing segment, primarily related to lower gas pipeline marketing margins due to less favorable commodity spreads, less favorable NGL marketing and storage activity, and negative impact on our gas marketing pipeline assets due to Winter Storm Uri, partially offset by favorable gas storage margins.

Supplemental Information on Unconsolidated Affiliates

The following tables present financial information related to unconsolidated affiliates during the three months ended March 31, 2021 and 2020, respectively:

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended March 31,
			2021		2020
		(millions)
DCP Sand Hills Pipeline, LLC			$	62	$	78
DCP Southern Hills Pipeline, LLC			24		20
Gulf Coast Express LLC			15		16
Front Range Pipeline LLC			9		11
Texas Express Pipeline LLC			4		4
Discovery Producer Services LLC (a)			8		(61)
Mont Belvieu 1 Fractionator			2		3
Mont Belvieu Enterprise Fractionator			1		3
Cheyenne Connector, LLC			3		—
Other			—		2
Total earnings from unconsolidated affiliates			$	128	$	76

(a) Includes an other than temporary impairment of $61 million taken on the investment in the first quarter of 2020.

Distributions received from unconsolidated affiliates were as follows:


	Three Months Ended March 31,
			2021		2020
		(millions)
DCP Sand Hills Pipeline, LLC			$	52	$	79
DCP Southern Hills Pipeline, LLC			25		22
Gulf Coast Express LLC			19		21
Front Range Pipeline LLC			12		12
Texas Express Pipeline LLC			5		5
Discovery Producer Services LLC			8		6
Mont Belvieu 1 Fractionator			2		4
Mont Belvieu Enterprise Fractionator			1		3
Cheyenne Connector, LLC			4		—
Other			1		1
Total distributions from unconsolidated affiliates			$	129	$	153

Results of Operations — Logistics and Marketing Segment


Operating Data
					Three months ended March 31, 2021
System	Approximate System Length (Miles)	Fractionators	Approximate Throughput Capacity (MBbls/d) (a)	Approximate Gas Throughput Capacity (Bcf/d) (a)		Pipeline Throughput (MBbls/d) (a)	Pipeline Throughput (TBtus/d) (a)	Fractionator Throughput (MBbls/d) (a)
Sand Hills pipeline	1,410	—	333	—		228	—	—
Southern Hills pipeline	950	—	128	—		105	—	—

Front Range pipeline	450	—	87	—		56	—	—
Texas Express pipeline	600	—	37	—		19	—	—
Other NGL pipelines (a)	1,110	—	310	—		170	—	—
Gulf Coast Express pipeline	500	—	—	500		—	0.47	—
Guadalupe pipeline	600	—	—	245		—	0.25	—
Cheyenne Connector	70	—	—	300		—	0.30	—
Mont Belvieu fractionators	—	2	—	—		—	—	43
Pipelines total	5,690	2	895	1,045		578	1.02	43

(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 2021 vs. 2020
		2021		2020			Increase (Decrease)		Percent

Operating revenues:
Sales of natural gas, NGLs and condensate		$	2,325	$	1,294		$	1,031	80	%
Transportation, processing and other		14		13			1		8	%
Trading and marketing (losses) gains, net		(241)		51			(292)		*
Total operating revenues		2,098		1,358			740		54	%
Purchases and related costs		(2,062)		(1,247)			815		65	%
Operating and maintenance expense		(6)		(7)			(1)		(14	%)
Depreciation and amortization expense		(3)		(3)			—		—	%
General and administrative expense		(1)		(2)			(1)		(50	%)


Earnings from unconsolidated affiliates (a)		120		137			(17)		(12	%)

Segment net income attributable to partners		$	146	$	236		$	(90)	(38	%)
Other data:
Segment adjusted gross margin (b)		$	36	$	111		$	(75)	(68	%)
Non-cash commodity derivative mark-to-market		$	(5)	$	42		$	(47)	*
NGL pipelines throughput (MBbls/d) (c)		578		677			(99)		(15	%)
Gas pipelines throughput (TBtu/d) (c)		1.0		0.80			0.2		25	%

* Percentage change is not meaningful.

(a) Earnings for certain unconsolidated affiliates include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

(b) Adjusted gross margin consists of total operating revenues less purchases and related costs. Segment adjusted 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”.

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

Three Months Ended March 31, 2021 vs. Three Months Ended March 31, 2020

Total Operating Revenues — Total operating revenues increased $740 million in 2021 compared to 2020, primarily as a result of the following:

•$1,382 million increase as a result of higher commodity prices before the impact of derivative activity; and

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

These increases were partially offset by:

•$351 million decrease attributable to lower NGL and gas sales volumes; and

•$292 million decrease as a result of commodity derivative activity attributable to an increase in realized cash settlement losses of $245 million and an increase in unrealized commodity derivative losses of $47 million due to movements in forward prices of commodities.

Purchases and Related Costs — Purchases and related costs increased $815 million in 2021 compared to 2020, primarily as a result of the commodity price and volume changes discussed above.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2021 compared to 2020, primarily due to decline of volumes from third party production on the Sand Hills pipeline.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $75 million in 2021 compared to 2020, primarily as a result of the following:

•$57 million decrease as a result of gas pipeline marketing margins due to less favorable commodity spreads in 2021, which includes unrealized derivatives losses of $47 million due to forward price movements of commodities in 2021;

•$13 million decrease as a result of less favorable NGL marketing and storage activity in 2021; and

•$5 million decrease as a result of Winter Storm Uri, which adversely impacted our gas marketing pipeline assets, with a large favorable offset at gas storage margins.

NGL Pipelines Throughput — NGL pipelines throughput decreased in 2021 compared to 2020 primarily due to decline of volumes from third party production on the Sand Hills pipeline.

Gas Pipelines Throughput — Gas throughput increased in 2021 compared to 2020, primarily as a result of the Cheyenne Connector pipeline coming online in the second quarter 2020.

Results of Operations — Gathering and Processing Segment


Operating Data
				Three months ended March 31, 2021
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	3,500	1,580	1,520	136
Midcontinent	6	24,500	1,110	799	65
Permian	10	15,400	1,200	858	93
South	8	7,000	1,730	900	67
Total	37	50,400	5,620	4,077	361

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

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


	Three Months Ended March 31,						Variance 2021 vs. 2020
			2021		2020			Increase (Decrease)		Percent
		(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate			$	1,338	$	713		$	625	88	%
Transportation, processing and other			104		99			5		5	%
Trading and marketing (losses) gains, net			(128)		101			(229)		*
Total operating revenues			1,314		913			401		44	%
Purchases and related costs			(1,069)		(513)			556		*
Operating and maintenance expense			(140)		(142)			(2)		(1	%)
Depreciation and amortization expense			(81)		(89)			(8)		(9	%)
General and administrative expense			(4)		(3)			1		33	%
Asset impairments			—		(746)			(746)		*
Other expense, net			—		(3)			(3)		*

Earnings (loss) from unconsolidated affiliates (a)			8		(61)			69		*
Segment net income (loss)			28		(644)			672		*
Segment net income attributable to noncontrolling interests			(1)		(1)			—		—	%
Segment net income (loss) attributable to partners			$	27	$	(645)		$	672	*
Other data:
Segment adjusted gross margin (b)			$	245	$	400		$	(155)	(39	%)
Non-cash commodity derivative mark-to-market			$	(48)	$	92		$	(140)	*
Natural gas wellhead (MMcf/d) (c)			4,077		4,940			(863)		(17	%)
NGL gross production (MBbls/d) (c)			361		404			(43)		(11	%)

* Percentage change is not meaningful.

(a) Earnings for certain unconsolidated affiliates include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities and impairment of $61 million of our equity investment in Discovery Producer Services LLC.

(b) Segment adjusted 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”.

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

Three Months Ended March 31, 2021 vs. Three Months Ended March 31, 2020

Total Operating Revenues — Total operating revenues increased $401 million in 2021 compared to 2020, primarily as a

result of the following:

•$792 million increase attributable to higher commodity prices, before the impact of derivative activity; and

•$5 million increase in transportation, processing and other.

These increases were partially offset by:

•$229 million decrease as a result of commodity derivative activity attributable to a increase in unrealized commodity derivative losses of $140 million due to movements in forward prices of commodities in 2021 and an increase in realized cash settlement losses of $89 million; and

•$167 million decrease primarily as a result of decreased volumes in all regions.

Purchases and Related Costs — Purchases and related costs increased $556 million in 2021 compared to 2020, primarily as a result of the commodity price and volume changes discussed above.

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

Earnings (Loss) from Unconsolidated Affiliates — Earnings (loss) from unconsolidated affiliates increased in 2021 compared to 2020, primarily as a result of an impairment in our equity investment in Discovery in 2020.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $155 million in 2021 compared to 2020, primarily as a result of the following:

•$162 million decrease as a result of unfavorable commodity derivative activity attributable to our corporate equity hedge program;

•$62 million decrease due primarily to lower base volumes and margins in the South, Permian, and Midcontinent regions, and lower margins in the DJ Basin due to offload processing fees; and

•$35 million decrease as a result of Winter Storm Uri, reflecting reduced volumes due to producer shut-ins, commodity derivative activity associated with swaps, and the net impact of producer payments and marketing activity.

This decrease was partially offset by:

•$104 million increase as a result of higher commodity prices.

Total Wellhead — Natural gas wellhead decreased in 2021 compared to 2020 primarily as a result of base declines and contract expirations in the South, base declines in Midcontinent and Permian regions, and lower volumes due to impact of Winter Storm Uri.

NGL Gross Production — NGL gross production decreased in 2021 compared to 2020, primarily as a result of base declines and contract expirations in the South, base declines in Midcontinent and Permian regions, and lower volumes due to impact of Winter Storm Uri, partially offset by lower ethane rejection across all regions.

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;

•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 that commodity prices will remain volatile and volumes may decline in the near term due to the COVID-19 pandemic and its impact on the global economy. We anticipate this will have an indirect impact on our leverage. While we have taken significant actions to mitigate the impact of the effects resulting of the COVID-19 pandemic and reduce our debt, our leverage may increase as a result of the current economic environment.

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

We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities or acquisitions.

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, 2021, we had unused borrowing capacity of $1,332 million, net of $58 million of outstanding borrowings and $10 million of letters of credit, under the Credit Agreement, of which at least $1,123 million would have been available to borrow for working capital and other general partnership purposes based on financial covenants set forth in the Credit Agreement. As of April 30, 2021, we had unused borrowing capacity of $1,276 million, net of $115 million of outstanding borrowings and $9 million of letters of credit under the Credit Agreement. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid.

Accounts Receivable Securitization Facility — As of March 31, 2021, we had $350 million of outstanding borrowings under our Securitization Facility at LIBOR market index rates plus a margin.

Issuance of Securities — In October 2020, 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, debt securities, and guarantees of debt securities.

In October 2020, we also 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, 2021, 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 condensed 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.

The Company qualifies for alternative disclosure under Rule 13-01 of Regulation S-X, 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. Summarized financial information is presented as follows. 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 $74 million and $87 million as of March 31, 2021 and December 31, 2020, respectively;

•Balances related to debt of $5.332 billion and $5.273 billion as of March 31, 2021 and December 31, 2020, respectively; and

•Interest expense, net of $76 million and $75 million for the three months ended March 31, 2021 and 2020, 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. During February 2021, Winter Storm Uri resulted in lower volumes and abnormally high gas prices for a period of days. A majority of our receivables associated with Winter Storm Uri have been collected. Certain counterparty billings during this time are under dispute and will take longer to collect than normal,

which have negatively impacted working capital at March 31, 2021. We believe the amounts due to us are owed and intend to vigorously pursue legal avenues to collect these receivables.

We had working capital deficits of $513 million and $613 million as of March 31, 2021 and December 31, 2020, respectively, driven by current maturities of long term debt of $504 million and $505 million, respectively. We had a net derivative working capital deficit of $19 million as of March 31, 2021 and surplus of $7 million as of December 31, 2020.

As of March 31, 2021, we had $5 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,
	2021		2020
	(millions)
Net cash (used in) provided by operating activities	$	(4)	$	314
Net cash used in investing activities	$	(14)	$	(103)
Net cash used in financing activities	$	(30)	$	(171)

Three Months Ended March 31, 2021 vs. Three Months Ended March 31, 2020

Operating Activities — Net cash provided by operating activities decreased $318 million in 2021 compared to the same period in 2020. The changes in net cash provided by operating activities are attributable to our net income (loss) 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 “Supplemental Information on Unconsolidated Affiliates” under “Results of Operations”.

Investing Activities — Net cash used in investing activities decreased $89 million in 2021 compared to the same period in 2020, primarily as a result of lower capital expenditures due to completed capital projects and lower investments in unconsolidated affiliates.

Financing Activities — Net cash used in financing activities decreased $141 million in 2021 compared to the same period in 2020, primarily as a result of lower distributions and higher net proceeds of debt in the first quarter of 2021.

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, or 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 expect to fund future acquisitions and capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, Securitization Facility and the issuance of additional debt and equity securities. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.

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 $81 million and $162 million during the three months ended March 31, 2021 and 2020, respectively.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders. See Note 12. “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, 2021, was as follows:


	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(millions)
Debt (a)	$	8,089	$	780	$	1,337	$	1,247	$	4,725
Finance lease obligations	31		4		10		8		9
Operating lease obligations	106		20		43		20		23
Purchase obligations (b)	9,786		1,591		3,026		2,273		2,896
Other long-term liabilities (c)	160		—		27		16		117
Total	$	18,172	$	2,395	$	4,443	$	3,564	$	7,770

(a) Includes interest payments on debt securities that have been issued. These interest payments are $280 million, $487 million, $422 million, and $1,625 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 gas supply, 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, 2021. 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, 2021 condensed consolidated balance sheet. The table above excludes non-cash obligations as well as $36 million of Executive Deferred Compensation Plan contributions and $8 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, 2021, we had no items that were classified as off-balance sheet obligations.

Reconciliation of Non-GAAP Measures

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

We define adjusted gross margin as total operating revenues, less purchases and related costs, and we define segment adjusted gross margin for each segment as total operating revenues for that segment less purchases and related costs for that segment. Our adjusted gross margin equals the sum of our segment adjusted gross margins. Adjusted gross margin and segment adjusted 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, adjusted gross margin and segment adjusted gross margin should not be considered an alternative to, or more meaningful than, operating revenues, gross margin, segment gross margin, 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.

We believe adjusted gross margin provides useful information to our investors because our management views our adjusted gross margin and segment adjusted gross margin as important performance measures that represent the results of product sales and purchases, a key component of our operations. We review our adjusted gross margin and segment adjusted gross margin monthly for consistency and trend analysis. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results.

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 pay 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 adjusted gross margin, segment adjusted 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 adjusted gross margin, segment adjusted 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.

Excess Free Cash Flow — We define Excess Free Cash Flow as Distributable Cash Flow, as defined above, less distributions to limited partners, less expansion capital expenditures, net of reimbursable projects, and contributions to equity method investments and certain other items. Expansion capital expenditures are cash expenditures to increase our cash flows, or 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).

Excess Free 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, and is useful to investors and management as a measure of our ability to generate cash particularly in light of an ongoing transition in the midstream industry that has shifted investor focus from distribution growth to capital discipline, cost efficiency, and balance-sheet strength. Once business needs and obligations are met, including cash reserves to provide funds for distribution payments on our units and the proper conduct of our business, which includes cash reserves for future capital expenditures and anticipated credit needs, this cash can be used to reduce debt, reinvest in the company for future growth, or return to unitholders.

Our definition of Excess Free Cash Flow is limited in that it does not represent residual cash flows available for discretionary expenditures. Therefore, we believe the use of Excess Free Cash Flow for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. Excess Free Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Excess Free Cash Flow in the same manner.

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


	Three Months Ended March 31,
			2021		2020
Reconciliation of Non-GAAP Measures		(millions)

Reconciliation of gross margin to adjusted gross margin:

Operating revenues			$	2,318	$	1,657
Cost of revenues
Purchases and related costs			1,763		872
Purchases and related costs from affiliates			55		36
Transportation and related costs from affiliates			219		238
Depreciation and amortization expense			91		99
Gross margin			190		412
Depreciation and amortization expense			91		99
Adjusted gross margin			$	281	$	511



Reconciliation of segment gross margin to segment adjusted gross margin:

Logistics and Marketing segment:
Operating revenues			$	2,098	$	1,358
Cost of revenues
Purchases and related costs			2,062		1,247
Depreciation and amortization expense			3		3
Segment gross margin			33		108
Depreciation and amortization expense			3		3
Segment adjusted gross margin			$	36	$	111



Gathering and Processing segment:
Operating revenues			$	1,314	$	913
Cost of revenues
Purchases and related costs			1,069		513
Depreciation and amortization expense			81		89
Segment gross margin			164		311
Depreciation and amortization expense			81		89
Segment adjusted gross margin			$	245	$	400


	Three Months Ended March 31,
			2021		2020
		(millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:

Logistics and Marketing segment:
Segment net income attributable to partners (a)			$	146	$	236
Non-cash commodity derivative mark-to-market			5		(42)
Depreciation and amortization expense, net of noncontrolling interest			3		3
Distributions from unconsolidated affiliates, net of earnings			1		10


Other expense			—		1
Adjusted segment EBITDA			$	155	$	208

Gathering and Processing segment:
Segment net income (loss) attributable to partners			$	27	$	(645)
Non-cash commodity derivative mark-to-market			48		(92)
Depreciation and amortization expense, net of noncontrolling interest			81		89
Asset impairments			—		746

Distributions from unconsolidated affiliates, net of earnings			—		67
Other expense			—		3
Adjusted segment EBITDA			$	156	$	168

(a) We recognized no lower of cost or net realizable value adjustment for the three months ended March 31, 2021. We recognized $4 million of lower of cost or net realizable value adjustments for the three months ended March 31, 2020.

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, 2020 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, 2020. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three months ended March 31, 2021 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2020. 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, 2020.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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 April 30, 2021 were as follows:

Commodity Swaps

Period

Commodity

Notional
Volume
- Short
Positions

Reference Price

Price Range

April 2021 — December 2021

Natural Gas

(145,000) MMBtu/d

NYMEX Final Settlement Price (a)

$2.35-$2.99/MMBtu

January 2022 — December 2022

Natural Gas

(80,000) MMBtu/d

NYMEX Final Settlement Price (a)

$2.40-$2.71/MMBtu

April 2021 — December 2021

NGLs

(10,567) Bbls/d (d)

Mt.Belvieu (b)

$.53-$.68/Gal

January 2022 — December 2022

NGLs

(494) Bbls/d (d)

Mt.Belvieu (b)

$.54/Gal

April 2021 — February 2022

Crude Oil

(5,685) Bbls/d (d)

NYMEX crude oil futures (c)

$45.46-$56.51/Bbl

March 2022 — February 2023

Crude Oil

(945) Bbls/d (d)

NYMEX crude oil futures (c)

$46.86-$48.85/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 2021 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 2021, 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	$	5
Natural gas prices	$	0.10	MMBtu	$	1
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	$	5
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, 2021:

Inventory

Period ended

Commodity

Notional Volume - Long
Positions

Fair Value
(millions)

Weighted
Average Price

March 31, 2021

Natural Gas

5,594,445

MMBtu

$2.10/MMBtu

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long
Positions

Fair Value
(millions)

Price Range

April 2021 — October 2021

Natural Gas

(20,852,500)

MMBtu

$2.60-$3.09/MMBtu

April 2021 — October 2021

Natural Gas

14,825,000

MMBtu

(1)

$2.55-$3.01/MMBtu

Natural Gas Asset Based Trading and Marketing - Our trading and marketing activities are subject to commodity price fluctuations in response to changes in supply and demand, market conditions and other factors.

We may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. The following table sets forth our commodity derivative instruments as of March 31, 2021:

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long Positions

Fair Value (millions)

Price Range (a)

April 2021 — December 2024

Natural Gas

(124,240,000)

MMBtu

(9)

$0.07-$0.09/MMBtu

April 2021 — December 2025

Natural Gas

139,792,500

MMBtu

$0.41-$0.56/MMBtu

(a) Represents the basis differential from NYMEX final settlement price for natural gas futures contracts for stated time period

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, 2021, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of March 31, 2021, 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, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We have not experienced any material impact to our internal controls over financial reporting despite the fact that most of our employees are working remotely due to the COVID-19 pandemic. We are continually monitoring and assessing the effect of the COVID-19 pandemic on our internal controls to minimize the impact on their design and operating effectiveness.

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, 2020 and (b) Note 14 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. For the disclosure of environmental proceedings with a governmental entity as a party pursuant to Item 103(c)(3)(iii) of Regulation S-K, the Company has elected to disclose matters where the Company reasonably believes such proceeding would result in monetary sanctions, exclusive of interest costs, of $1 million or more.

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, 2020. There are no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2020.

Exhibit Number

Description

3.1

Certificate of Limited Partnership of DCP Midstream Partners, LP dated August 5, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP's Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on September 16, 2005).

3.2

Certificate of Amendment to Certificate of Limited Partnership of DCP Midstream Partners, LP dated January 11, 2017 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 17, 2017).

3.3

Fifth Amended and Restated Agreement of Limited Partnership of DCP Midstream, LP dated November 6, 2019 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2019).

10.1

Form of Strategic Performance Unit Grant Agreement under the DCP Midstream, LP 2016 Long-Term Incentive Plan.

10.2

Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream, LP 2016 Long-Term Incentive Plan.

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, 2021, formatted in Inline XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (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 6, 2021

By:

/s/ Wouter T. van Kempen

Name:

Wouter T. van Kempen

Title:

President and Chief Executive Officer

(Principal Executive Officer)

Date: May 6, 2021

By:

/s/ Sean P. O'Brien

Name:

Sean P. O'Brien

Title:

Group Vice President and Chief Financial Officer

(Principal Financial Officer)