DCP Midstream, LP - Quarter Report: 2021 September (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 September 30, 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 October 29, 2021, there were 208,373,672 common units representing limited partnership interests outstanding.

DCP MIDSTREAM, LP

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2021

TABLE OF CONTENTS



Item		Page
	PART I. FINANCIAL INFORMATION
1	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2021 and 2020	3
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2021 and 2020	4
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2021 and 2020	5
	Condensed Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2021	6
	Condensed Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2020	7
	Notes to the Condensed Consolidated Financial Statements	8
2	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
3	Quantitative and Qualitative Disclosures about Market Risk	54
4	Controls and Procedures	57
	PART II. OTHER INFORMATION
1	Legal Proceedings	57
1A	Risk Factors	57
5	Other Information	57
6	Exhibits	59
	Signatures	60

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
LIBOR						London Interbank Offered Rate
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
OPIS						Oil Price Information Service
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, 2024
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 September 30, 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)


	September 30, 2021		December 31, 2020
ASSETS	(millions)
Current assets:
Cash and cash equivalents	$	3	$	52


Accounts receivable:
Trade, net of allowance for credit losses of $2 and $2 million, respectively	1,045		572
Affiliates	484		238
Other	17		10
Inventories	58		38
Unrealized gains on derivative instruments	141		63

Collateral cash deposits	231		14
Other	22		21
Total current assets	2,001		1,008
Property, plant and equipment, net	7,775		7,993

Intangible assets, net	41		44
Investments in unconsolidated affiliates	3,577		3,641
Unrealized gains on derivative instruments	13		16
Operating lease assets	93		85
Other long-term assets	196		170
Total assets	$	13,696	$	12,957
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,037	$	536
Affiliates	246		161
Other	13		23

Current debt	355		505
Unrealized losses on derivative instruments	321		56
Accrued interest	72		85
Accrued taxes	71		59
Accrued wages and benefits	50		70
Capital spending accrual	3		4

Other	118		122
Total current liabilities	2,286		1,621
Long-term debt	5,325		5,119
Unrealized losses on derivative instruments	48		7
Deferred income taxes	30		30
Operating lease liabilities	81		76
Other long-term liabilities	260		243
Total liabilities	8,030		7,096
Commitments and contingent liabilities (see note 14)
Equity:
Series A preferred limited partners (500,000 preferred units authorized, issued and outstanding, respectively)	499		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 (208,373,672 and 208,351,528 common units authorized, issued and outstanding, respectively)	4,885		5,090
Accumulated other comprehensive loss	(6)		(7)
Total partners’ equity	5,640		5,834
Noncontrolling interests	26		27
Total equity	5,666		5,861
Total liabilities and equity	$	13,696	$	12,957

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	1,935	$	1,204	$	5,395	$	3,378
Sales of natural gas, NGLs and condensate to affiliates	921		262		2,143		653
Transportation, processing and other	144		109		387		330
Trading and marketing (losses) gains, net	(173)		11		(695)		156

Total operating revenues	2,827		1,586		7,230		4,517
Operating costs and expenses:
Purchases and related costs	2,181		944		5,484		2,539
Purchases and related costs from affiliates	81		32		183		89
Transportation and related costs from affiliates	249		242		720		710
Operating and maintenance expense	168		146		482		447
Depreciation and amortization expense	89		92		273		284
General and administrative expense	63		66		158		173

Asset impairments	—		—		20		746
Other expense (income), net	2		4		(4)		12
Loss on sale of assets, net	—		—		1		—
Restructuring costs	—		—		—		9
Total operating costs and expenses	2,833		1,526		7,317		5,009
Operating (loss) income	(6)		60		(87)		(492)

Earnings from unconsolidated affiliates	134		130		393		331
Interest expense, net	(73)		(77)		(227)		(226)
Income (loss) before income taxes	55		113		79		(387)
Income tax expense	—		(1)		—		(2)
Net income (loss)	55		112		79		(389)
Net income attributable to noncontrolling interests	(1)		(1)		(3)		(3)
Net income (loss) attributable to partners	54		111		76		(392)

Series A preferred limited partners' interest in net income	(9)		(9)		(28)		(28)
Series B preferred limited partners' interest in net income	(4)		(3)		(10)		(9)
Series C preferred limited partners' interest in net income	(3)		(3)		(7)		(7)

Net income (loss) allocable to limited partners	$	38	$	96	$	31	$	(436)
Net income (loss) per limited partner unit — basic and diluted	$	0.18	$	0.46	$	0.15	$	(2.09)

Weighted-average limited partner units outstanding — basic	208.4		208.3		208.4		208.3
Weighted-average limited partner units outstanding — diluted	208.7		208.7		208.6		208.3

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
Net income (loss)	$	55	$	112	$	79	$	(389)
Other comprehensive income:


Total other comprehensive income	1		—		1		—
Total comprehensive income (loss)	56		112		80		(389)
Total comprehensive income attributable to noncontrolling interests	(1)		(1)		(3)		(3)
Total comprehensive income (loss) attributable to partners	$	55	$	111	$	77	$	(392)

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Nine Months Ended September 30,
	2021		2020
	(millions)
OPERATING ACTIVITIES:
Net income (loss)	$	79	$	(389)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	273		284
Earnings from unconsolidated affiliates	(393)		(331)
Distributions from unconsolidated affiliates	462		489
Net unrealized losses (gains) on derivative instruments	296		(66)

Asset impairments	20		746


Other, net	13		27
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable	(726)		185
Inventories	(20)		13
Accounts payable	576		(230)



Other assets and liabilities	(325)		63
Net cash provided by operating activities	255		791
INVESTING ACTIVITIES:
Capital expenditures	(69)		(125)


Investments in unconsolidated affiliates	(4)		(107)
Distributions from unconsolidated affiliates	—		5
Proceeds from sale of assets	—		2

Net cash used in investing activities	(73)		(225)
FINANCING ACTIVITIES:
Proceeds from debt	3,380		3,958
Payments of debt	(3,332)		(4,137)






Distributions to preferred limited partners	(35)		(34)

Distributions to limited partners and general partner	(244)		(325)
Distributions to noncontrolling interests	(4)		(3)
Debt issuance costs	—		(8)


Other	—		(1)
Net cash used in financing activities	(235)		(550)
Net change in cash, cash equivalents and restricted cash	(53)		16
Cash, cash equivalents and restricted cash, beginning of period	56		1
Cash, cash equivalents and restricted cash, end of period	$	3	$	17

Reconciliation of cash, cash equivalents, and restricted cash:	September 30, 2021		September 30, 2020
Cash and cash equivalents	$	3	$	14
Restricted cash included in other current assets	—		3

Total cash, cash equivalents, and restricted cash	$	3	$	17

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
Net income (loss)		10		3		2		(46)		—		1		(30)

Distributions to unitholders		(18)		(3)		(2)		(82)		—		—		(105)
Distributions to noncontrolling interests		—		—		—		—		—		(1)		(1)
Equity based compensation		—		—		—		1		—		—		1
Balance, June 30, 2021		$	490	$	156	$	106	$	4,925	$	(7)	$	27	$	5,697
Net income		9		4		3		38		—		1		55
Other comprehensive income		—		—		—		—		1		—		1
Distributions to unitholders		—		(4)		(3)		(81)		—		—		(88)
Distributions to noncontrolling interests		—		—		—		—		—		(2)		(2)
Equity based compensation		—		—		—		3		—		—		3
Balance, September 30, 2021		$	499	$	156	$	106	$	4,885	$	(6)	$	26	$	5,666

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
Net income	10		3		2		32		—		1		48


Distributions to unitholders	(18)		(3)		(2)		(81)		—		—		(104)
Distributions to noncontrolling interests	—		—		—		—		—		(1)		(1)
Balance, June 30, 2020	$	490	$	156	$	106	$	5,086	$	(7)	$	28	$	5,859
Net income	9		3		3		96		—		1		112

Distributions to unitholders	—		(3)		(3)		(82)		—		—		(88)
Distributions to noncontrolling interests	—		—		—		—		—		(1)		(1)
Balance, September 30, 2020	$	499	$	156	$	106	$	5,100	$	(7)	$	28	$	5,882

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 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 15 - 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 September 30, 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 nine months ended September 30, 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 September 30, 2021
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	895	$	715	$	(695)	$	915
Sales of NGLs and condensate (a)	1,768		1,139		(966)		1,941
Transportation, processing and other	19		126		(1)		144
Trading and marketing losses, net (b)	(14)		(159)		—		(173)
Total operating revenues	$	2,668	$	1,821	$	(1,662)	$	2,827

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)


	Nine Months Ended September 30, 2021
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	2,625	$	1,832	$	(1,673)	$	2,784
Sales of NGLs and condensate (a)	4,296		2,686		(2,228)		4,754
Transportation, processing and other	46		342		(1)		387
Trading and marketing losses, net (b)	(284)		(411)		—		(695)
Total operating revenues	$	6,683	$	4,449	$	(3,902)	$	7,230

(a) Includes $589 million and $1,473 million for the three and nine months ended September 30, 2021, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment. For the three and nine months ended September 30, 2021, these revenues are net of $741 million and $1,692 million, respectively, of buy-sell purchases related to buy-sell revenues of $786 million and $1,867 million, respectively, 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 September 30, 2020
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	437	$	330	$	(308)	$	459
Sales of NGLs and condensate (a)	951		456		(400)		1,007
Transportation, processing and other	13		97		(1)		109
Trading and marketing gains (losses), net (b)	37		(26)		—		11
Total operating revenues	$	1,438	$	857	$	(709)	$	1,586


	Nine Months Ended September 30, 2020
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	1,203	$	927	$	(842)	$	1,288
Sales of NGLs and condensate (a)	2,592		1,125		(974)		2,743
Transportation, processing and other	37		294		(1)		330
Trading and marketing gains, net (b)	114		42		—		156
Total operating revenues	$	3,946	$	2,388	$	(1,817)	$	4,517

(a) Includes $303 million and $2,006 million for the three and nine months ended September 30, 2020, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment, which are not within the scope of Topic 606.

(b) Not within the scope of Topic 606.

The revenue expected to be recognized in the future related to performance obligations that are not satisfied is approximately $467 million as of September 30, 2021. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to be recognized through 2031 with a weighted average remaining life of four years as of September 30, 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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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


	September 30,
	2021
	(millions)
Balance, beginning of period	$	35


Revenue recognized (a)	(2)
Balance, end of period	$	33

(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 September 30, 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 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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense	$	39	$	39	$	116	$	121
General and administrative expense	$	44	$	43	$	109	$	113
Restructuring costs	$	—	$	—	$	—	$	9

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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	893	$	247	$	2,066	$	616
Purchases and related costs from affiliates	$	45	$	15	$	94	$	52
Transportation and related costs from affiliates	$	39	$	26	$	113	$	70
Operating and maintenance and general administrative expenses	$	3	$	4	$	9	$	10
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	—	$	1	$	4	$	2
Purchases and related costs from affiliates	$	12	$	2	$	27	$	2
Transportation and related costs from affiliates	$	1	$	1	$	1	$	1
Operating and maintenance and general administrative expenses	$	1	$	—	$	1	$	1
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	28	$	14	$	73	$	35
Transportation, processing, and other to affiliates	$	3	$	3	$	13	$	9
Purchases and related costs from affiliates	$	24	$	15	$	62	$	35
Transportation and related costs from affiliates	$	209	$	215	$	606	$	639

We had balances with affiliates as follows:


	September 30, 2021		December 31, 2020
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	457	$	217
Accounts payable	$	158	$	89
Other assets	$	1	$	1
Enbridge (including its affiliates):

Accounts payable	$	4	$	2


Unconsolidated affiliates:
Accounts receivable	$	27	$	21
Accounts payable	$	84	$	70

5. Inventories

Inventories were as follows:


	September 30, 2021		December 31, 2020
	(millions)
Natural gas	$	29	$	18
NGLs	29		20
Total inventories	$	58	$	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 for the three and nine months

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

ended September 30, 2021 . We recognized zero and $6 million of lower of cost or net realizable value adjustments for the three and nine months ended September 30, 2020.

6. Property, Plant and Equipment

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


	Depreciable Life	September 30, 2021		December 31, 2020
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,660	$	7,680
Processing, storage and terminal facilities	35 — 60 Years	5,059		4,986
Other	3 — 30 Years	585		585
Finance lease assets	2 — 5 Years	28		25
Construction work in progress		87		144
Property, plant and equipment		13,419		13,420
Accumulated depreciation		(5,644)		(5,427)
Property, plant and equipment, net		$	7,775	$	7,993

There were no construction projects with capitalized interest during the three months ended September 30, 2021. Capitalized interest on construction projects was $1 million for the three months ended September 30, 2020, and $1 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively.

Depreciation expense was $88 million and $90 million for the three months ended September 30, 2021 and 2020, respectively, and $269 million and $279 million for the nine months ended September 30, 2021 and 2020, respectively.

7. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:


		Carrying Value as of
	Percentage Ownership	September 30, 2021		December 31, 2020
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,707	$	1,723
DCP Southern Hills Pipeline, LLC	66.67%	721		734
Gulf Coast Express LLC	25.00%	425		436
Front Range Pipeline LLC	33.33%	193		198
Texas Express Pipeline LLC	10.00%	94		97
Discovery Producer Services LLC	40.00%	231		244
Mont Belvieu 1 Fractionator	20.00%	7		7
Mont Belvieu Enterprise Fractionator	12.50%	27		26
Cheyenne Connector, LLC	50.00%	149		152
Panola Pipeline Company, LLC	15.00%	20		21
Other	Various	3		3
Total investments in unconsolidated affiliates		$	3,577	$	3,641

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
DCP Sand Hills Pipeline, LLC	$	68	$	73	$	202	$	221
DCP Southern Hills Pipeline, LLC	21		19		67		59
Gulf Coast Express LLC	16		17		46		49
Front Range Pipeline LLC	10		9		28		29
Texas Express Pipeline LLC	5		4		14		13
Discovery Producer Services LLC (a)	2		(3)		13		(63)
Mont Belvieu 1 Fractionator	6		3		12		9
Mont Belvieu Enterprise Fractionator	2		4		1		10
Cheyenne Connector, LLC	4		3		8		3
Other	—		1		2		1
Total earnings from unconsolidated affiliates	$	134	$	130	$	393	$	331

(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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
Statements of operations:
Operating revenue	$	535	$	523	$	1,552	$	1,560
Operating expenses	$	231	$	196	$	631	$	572
Net income	$	303	$	326	$	917	$	985


	September 30, 2021		December 31, 2020
	(millions)
Balance sheets:
Current assets	$	384	$	355
Long-term assets	7,331		7,510
Current liabilities	(208)		(177)
Long-term liabilities	(253)		(258)
Net assets	$	7,254	$	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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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

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

Commodity Derivative Assets and Liabilities

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

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

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

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

The following table presents the financial instruments carried at fair value on a recurring basis as of September 30, 2021 and December 31, 2020, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:


	September 30, 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	$	58	$	83	$	—	$	141	$	21	$	42	$	—	$	63
Short-term investments (a)	$	2	$	1	$	—	$	3	$	—	$	—	$	—	$	—

Long-term assets:
Commodity derivatives	$	3	$	7	$	3	$	13	$	1	$	13	$	2	$	16
Investments in marketable securities (a)	$	31	$	—	$	—	$	31	$	22	$	1	$	—	$	23
Current liabilities:
Commodity derivatives	$	(90)	$	(226)	$	(5)	$	(321)	$	(19)	$	(34)	$	(3)	$	(56)

Long-term liabilities:
Commodity derivatives	$	(7)	$	(38)	$	(3)	$	(48)	$	—	$	(6)	$	(1)	$	(7)

(a) $3 million and $4 million recorded within "other" current assets and $31 million and $19 million recorded within "Other long-term assets" as of September 30, 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 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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)


	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended September 30, 2021 (a):
Beginning balance	$	1	$	1	$	(9)	$	(5)
Net unrealized gains (losses) included in earnings	1		2		(10)		2

Transfers out of Level 3	(2)		—		12		—
Settlements	—		—		2		—


Ending balance	$	—	$	3	$	(5)	$	(3)
Net unrealized gains (losses) on derivatives still held included in earnings	$	—	$	2	$	(3)	$	2
Three months ended September 30, 2020 (a):
Beginning balance	$	1	$	—	$	(3)	$	(4)
Net unrealized (losses) gains included in earnings	(1)		4		(1)		3

Transfers out of Level 3	—		—		2		—
Settlements	—		—		1		—


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


	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Nine months ended September 30, 2021 (a):
Beginning balance	$	—	$	2	$	(3)	$	(1)
Net unrealized gains (losses) included in earnings	—		1		(16)		(3)

Transfers out of Level 3	—		—		9		1
Settlements	—		—		5		—


Ending balance	$	—	$	3	$	(5)	$	(3)
Net unrealized gains (losses) on derivatives still held included in earnings	$	—	$	1	$	(5)	$	(3)
Nine months ended September 30, 2020 (a):
Beginning balance	$	4	$	—	$	(1)	$	(3)
Net unrealized (losses) gains included in earnings	(1)		8		8		2

Transfers out of Level 3	—		(4)		—		—
Settlements	(3)		—		(8)		—


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

(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three and nine months ended September 30, 2021 and 2020.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 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.

September 30, 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

$2.24-$3.40

$2.71

Per MMBtu

Liabilities

NGLs

(6)

Market approach

Longer dated forward curve prices

$0.33-$1.75

$0.92

Per gallon

Natural gas

(2)

Market approach

Longer dated forward curve prices

$2.24-$3.30

$2.50

Per MMBtu

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

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 nine months ended September 30, 2021 we recognized a $7 million impairment associated with certain assets in the Midcontinent region of our Gathering and Processing segment that were sold in July 2021, and determined that a triggering event occurred due to a negative outlook for long-term volume forecasts for an asset in our Logistics and Marketing segment resulting in an impairment of $13 million. During the nine months ended September 30, 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”).

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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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 September 30, 2021 and December 31, 2020, the carrying value and fair value of our total debt, including current maturities, were as follows:


		September 30, 2021				December 31, 2020
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)

Total debt		$	5,687	$	6,274	$	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:


	Location in Condensed Consolidated Balance Sheet	As of
		September 30, 2021		December 31, 2020
		(millions)
Assets
Operating lease assets	Operating lease assets	$	93	$	85
Finance lease assets	Property, plant and equipment	28		25
Total right of use assets		$	121	$	110

Liabilities
Current liabilities
Operating lease liabilities	Other current liabilities	$	26	$	24
Finance lease liabilities	Current debt	5		5
Noncurrent liabilities
Operating lease liabilities	Operating lease liabilities	$	81	$	76
Finance lease liabilities	Long-term debt	21		22
Total lease liabilities		$	133	$	127

Variable lease costs primarily consist of common area maintenance on our office spaces and variable transportation costs.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

The components of lease expense are as follows:


	Location in Condensed Consolidated Statement of Operations	Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(millions)
Operating lease cost	Operating and maintenance expense	$	7	$	7	$	21	$	21
Finance lease cost
Amortization of right of use assets	Depreciation and amortization expense	1		1		2		2
Interest on lease liabilities	Interest expense	1		1		1		1
Variable lease cost	Operating and maintenance expense	1		2		3		5
Short term lease cost	Operating and maintenance expense	1		1		2		3
Total lease cost		$	11	$	12	$	29	$	32

Maturities of operating and finance lease liabilities under non-cancelable leases as of September 30, 2021 are as follows:


	Future Minimum Lease Payments as of September 30, 2021
	Operating Leases		Finance Leases
	(millions)
2021 - remainder	$	7	$	2
2022	29		6
2023	26		6
2024	17		7
2025	13		3
Thereafter	26		9
Total lease payments	$	118	$	33
Less imputed interest	(11)		(7)
Total lease liabilities	$	107	$	26

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

As of September 30, 2021, the Company had minimum commitments related to additional operating lease contracts for which the commencement date has not yet been reached, primarily for an office lease, of approximately $19 million.

Supplemental cash flow information related to leases is as follows:


	Nine Months Ended September 30,
	2021			2020
	(millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	23		$	20
Operating cash flows from finance leases	3			3
Financing cash flows from finance leases	1			1
Right-of-use assets obtained in exchange for operating lease obligations:	$	26		$	6
Right-of-use assets obtained in exchange for finance lease obligations:	$	3		$	5

Other information related to operating leases as follows:
Weighted average remaining lease term	5 years			6 years
Weighted average discount rate	4.00		%	4.00		%

Other information related to finance leases as follows:
Weighted average remaining lease term	4 years			5 years
Weighted average discount rate	3.00		%	3.00		%

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

10. Debt


	September 30, 2021		December 31, 2020
	(millions)




Senior notes:




Issued September 2011, interest at 4.750% payable semi-annually, due September 2021	$	—	$	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 1.440% as of September 30, 2021, due December 2024	552		—
Accounts receivable securitization facility:
Accounts receivable securitization facility, interest at 0.980% as of September 30, 2021, due August 2024	350		350
Fair value adjustments related to interest rate swap fair value hedges (a)	16		17
Unamortized issuance costs	(33)		(38)
Unamortized discount, net	(6)		(7)
Finance lease liabilities	26		27
Total debt	5,680		5,624
Current finance lease liabilities	5		5
Current debt	350		500
Total long-term debt	$	5,325	$	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.

Senior Notes Redemption

On June 30, 2021, we repaid, at par, prior to maturity all $500 million aggregate principal amount outstanding of our 4.75% Senior Notes due September 2021 using borrowings under our revolving credit facility.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 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 September 30, 2021, we had unused borrowing capacity of $846 million, net of $552 million of outstanding borrowings and $2 million of letters of credit, under the Credit Agreement, of which $846 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

On August 2, 2021 we entered into an amendment to our Securitization Facility to extend the term of the facility until August 12, 2024. The amendment also includes Environmental, Social, and Governance linked Key Performance Indicators that increase or decrease certain fees based on our safety performance relative to our peers, and year-over-year change in our greenhouse gas emissions intensity rate. The Securitization Facility provides up to $350 million of borrowing capacity through August 2024 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 September 30, 2021, DCP Receivables had approximately $963 million of our accounts receivable securing borrowings of $350 million under the Securitization Facility.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

The maturities of our debt as of September 30, 2021 are as follows:


	Debt Maturities
	(millions)
2021	$	—
2022	350
2023	500
2024	902
2025	825
Thereafter	3,100
Total debt	$	5,677

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 September 30, 2021, we had cash deposits of $231 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of September 30, 2021, we held letters of credit of $103 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 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 financial 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:

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)


	September 30, 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	$	154	$	—	$	154	$	79	$	—	$	79

Liabilities:
Commodity derivatives	$	(369)	$	—	$	(369)	$	(63)	$	—	$	(63)

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 September 30, 2021 and December 31, 2020.


Balance Sheet Line Item	September 30, 2021		December 31, 2020		Balance Sheet Line Item	September 30, 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	$	141	$	63	Unrealized losses on derivative instruments — current	$	(321)	$	(56)
Unrealized gains on derivative instruments — long-term	13		16		Unrealized losses on derivative instruments — long-term	(48)		(7)
Total	$	154	$	79	Total	$	(369)	$	(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 September 30, 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	1		—		—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(1)	$	(6)	$	1	$	(6)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	—	$	—	$	—	$	—

(a) Relates to Discovery, an unconsolidated affiliate.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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 nine months ended September 30, 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	1		—		—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(1)	$	(6)	$	1	$	(6)
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 September 30, 2020:


	Interest Rate Cash Flow Hedges		Commodity Cash Flow Hedges		Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(2)	$	(6)	$	1	$	(7)

Net deferred (losses) gains in AOCI (ending balance)	$	(2)	$	(6)	$	1	$	(7)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1)	$	—	—		$	(1)

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 nine months ended September 30, 2020:


	Interest Rate Cash Flow Hedges		Commodity Cash Flow Hedges		Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(2)	$	(6)	$	1	$	(7)

Net deferred (losses) gains in AOCI (ending balance)	$	(2)	$	(6)	$	1	$	(7)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1)	$	—	$	—	$	(1)

(a) Relates to Discovery, an unconsolidated affiliate.

For the nine months ended September 30, 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 nine months ended September 30, 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 and Nine Months Ended September 30, 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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)				(millions)
Realized (losses) gains	$	(66)	$	22	$	(399)	$	90
Unrealized (losses) gains	(107)		(11)		(296)		66
Trading and marketing (losses) gains, net	$	(173)	$	11	$	(695)	$	156

We do not have any derivative financial instruments that are designated 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.


	September 30, 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 Long (Short) Position (Bbls)	Net (Short) Long Position (MMBtu)
2021	(405,000)	(31,457,300)	168,546	(2,245,000)
2022	(1,286,000)	(59,980,200)	(8,817,555)	(2,362,500)
2023	(446,000)	912,500	(1,296,000)	(13,605,000)
2024	—	—	(1,446,000)	1,380,000
2025	—	—	(1,440,000)	21,020,000
2026	—	—	(1,080,000)	457,500

	September 30, 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 (Short) Position (MMBtu)
2020	(253,000)	(14,287,500)	(932,160)	5,600,000
2021	(791,000)	(65,332,500)	(8,471,590)	(735,000)
2022	(43,000)	(21,900,000)	(1,486,842)	12,775,000
2023	—	—	(1,440,000)	7,300,000
2024	—	—	(1,440,000)	7,630,000
2025	—	—	(960,000)	1,365,000

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

12. Partnership Equity and Distributions

Common Units — During the nine months ended September 30, 2021 and 2020, we issued no common units pursuant to our at-the-market program. As of September 30, 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 September 30, 2021.

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
August 13, 2021	$	0.39	$	81
May 14, 2021	$	0.39	$	82
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
June 15, 2021	$	36.8750	$	18
December 15, 2020	$	36.8750	$	19
June 15, 2020	$	36.8750	$	18





Distributions to Series B Preferred unitholders
September 15, 2021	$	0.4922	$	4
June 15, 2021	$	0.4922	$	3
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
July 15, 2021	$	0.4969	$	2
April 15, 2021	$	0.4969	$	2
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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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 319,350 restricted phantom units outstanding as of September 30, 2020 that were not included in the calculation of diluted net loss per unit for the nine months ended September 30, 2020 because including them would have been anti-dilutive.

Basic and diluted net income per limited partner unit was calculated as follows for the three and nine months ended September 30, 2021 and 2020, respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions, except per unit amounts)

Net income (loss) attributable to limited partners	$	38	$	96	$	31	$	(436)
Weighted average limited partner units outstanding, basic	208,368,605		208,342,746		208,363,754		208,334,185
Dilutive effects of nonvested restricted phantom units	291,364		319,350		188,470		—
Weighted average limited partner units outstanding, diluted	208,659,969		208,662,096		208,552,224		208,334,185
Net income (loss) per limited partner unit, basic and diluted	$	0.18	$	0.46	$	0.15	$	(2.09)

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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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 June 2020, the New Mexico Environment Department (the "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. Separately, in August 2020, the NMED issued an Administrative Compliance Order (the "August ACO" and, together with the June ACO, the "ACOs") alleging that emissions at four of our natural gas processing plants exceeded respective air permit limits or requirements during various instances also what were instances of 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 formally challenged the allegations and asserted penalties of the ACOs 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 ACOs and engaged in information exchanges and discussions with NMED about the propriety of the allegations and asserted penalties. In September 2021, we resolved the ACOs in a Settlement Agreement with the NMED for an administrative civil penalty of $950,000, certain reporting and flare operation requirements at our New Mexico gas plants, and an agreement to retire the gas processing elements and equipment at our Eunice Gas Plant in Lea County, New Mexico.

•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.

•In 2018, the Colorado Department of Public Health and Environment (“CDPHE”) issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants, which we had self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the plant's air permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as an economic benefit payment generally covering the period when the flare was required to be included in the facility air permit; while the revised air permit was issued in May 2019, this matter remains unresolved. Subsequently, in July 2020 CDPHE issued a Notice of Violation in relation to amine treater emissions at this gas processing plant, which we had self-disclosed to CDPHE in April 2020. We are still exchanging information and holding discussions with CDPHE as to this and the foregoing flare-related enforcement matter, including possible settlement terms, although these matters, which have since been combined, may end up in formal legal proceedings. It is possible that resolution of this matter may include an administrative penalty and economic benefit payment, further revising the facility air permit, or installation of emissions management equipment, or a combination of these, that could, in the aggregate, exceed the disclosure threshold amount described above, although we do not believe that resolution of this matter would have a material adverse effect on our results of operations, financial position, or cash flows.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

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.

The following tables set forth our segment information:

Three Months Ended September 30, 2021


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	2,668	$	1,821	$	—	$	(1,662)	$	2,827
Adjusted gross margin (a)	$	35	$	281	$	—	$	—	$	316
Operating and maintenance expense	(11)		(157)		—		—		(168)
General and administrative expense	(1)		(4)		(58)		—		(63)
Depreciation and amortization expense	(3)		(80)		(6)		—		(89)

Other expense, net	—		(2)		—		—		(2)



Earnings from unconsolidated affiliates	133		1		—		—		134
Interest expense	—		—		(73)		—		(73)

Net income (loss)	$	153	$	39	$	(137)	$	—	$	55
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	153	$	38	$	(137)	$	—	$	54
Non-cash derivative mark-to-market	$	(7)	$	(100)	$	—	$	—	$	(107)

Capital expenditures	$	2	$	25	$	1	$	—	$	28
Investments in unconsolidated affiliates, net	$	4	$	—	$	—	$	—	$	4

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

Nine Months Ended September 30, 2021


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	6,683	$	4,449	$	—	$	(3,902)	$	7,230
Adjusted gross margin (a)	$	78	$	765	$	—	$	—	$	843
Operating and maintenance expense	(29)		(443)		(10)		—		(482)
General and administrative expense	(4)		(12)		(142)		—		(158)
Depreciation and amortization expense	(9)		(243)		(21)		—		(273)
Asset impairments	(13)		(7)		—		—		(20)
Other income (expense), net	5		(1)		—		—		4


Loss on sale of assets, net	—		(1)		—		—		(1)

Earnings from unconsolidated affiliates	380		13		—		—		393
Interest expense	—		—		(227)		—		(227)

Net income (loss)	$	408	$	71	$	(400)	$	—	$	79
Net income attributable to noncontrolling interests	—		(3)		—		—		(3)
Net income (loss) attributable to partners	$	408	$	68	$	(400)	$	—	$	76
Non-cash derivative mark-to-market	$	(47)	$	(249)	$	—	$	—	$	(296)

Capital expenditures	$	2	$	62	$	5	$	—	$	69
Investments in unconsolidated affiliates, net	$	4	$	—	$	—	$	—	$	4

Three Months Ended September 30, 2020


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	1,438	$	857	$	—	$	(709)	$	1,586
Adjusted gross margin (a)	$	88	$	280	$	—	$	—	$	368
Operating and maintenance expense	(8)		(135)		(3)		—		(146)
General and administrative expense	(1)		(8)		(57)		—		(66)
Depreciation and amortization expense	(3)		(82)		(7)		—		(92)

Other expense, net	(2)		(2)		—		—		(4)



Earnings (loss) from unconsolidated affiliates	132		(2)		—		—		130
Interest expense	—		—		(77)		—		(77)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	206	$	51	$	(145)	$	—	$	112
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	206	$	50	$	(145)	$	—	$	111
Non-cash derivative mark-to-market	$	28	$	(39)	$	—	$	—	$	(11)

Capital expenditures	$	1	$	13	$	9	$	—	$	23
Investments in unconsolidated affiliates, net	$	12	$	—	$	—	$	—	$	12

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

Nine Months Ended September 30, 2020:


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	3,946	$	2,388	$	—	$	(1,817)	$	4,517
Adjusted gross margin (a)	$	268	$	911	$	—	$	—	$	1,179
Operating and maintenance expense	(24)		(411)		(12)		—		(447)
General and administrative expense	(4)		(15)		(154)		—		(173)
Depreciation and amortization expense	(9)		(253)		(22)		—		(284)
Asset impairments	—		(746)		—		—		(746)
Other expense, net	(6)		(4)		(2)		—		(12)


Restructuring costs	—		—		(9)		—		(9)
Earnings (loss) from unconsolidated affiliates	394		(63)		—		—		331
Interest expense	—		—		(226)		—		(226)
Income tax expense	—		—		(2)		—		(2)
Net income (loss)	$	619	$	(581)	$	(427)	$	—	$	(389)
Net income attributable to noncontrolling interests	—		(3)		—		—		(3)
Net income (loss) attributable to partners	$	619	$	(584)	$	(427)	$	—	$	(392)

Non-cash derivative mark-to-market	$	75	$	(9)	$	—	$	—	$	66
Non-cash lower of cost or net realizable value adjustments	$	6	$	—	$	—	$	—	$	6
Capital expenditures	$	2	$	112	$	11	$	—	$	125
Investments in unconsolidated affiliates, net	$	102	$	—	$	—	$	—	$	102


	September 30,		December 31,
	2021		2020
	(millions)
Segment long-term assets:
Gathering and Processing	$	7,603	$	7,788
Logistics and Marketing	3,871		3,929
Other (b)	221		232
Total long-term assets	11,695		11,949
Current assets	2,001		1,008
Total assets	$	13,696	$	12,957

(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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Nine Months Ended September 30, 2021 and 2020

(unaudited)

16. Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2021		2020
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	234	$	222
Cash paid for income taxes, net of income tax refunds	$	3	$	2
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	8	$	5
Other non-cash changes in property, plant and equipment	$	(2)	$	—
Other non-cash activities:
Right-of-use assets obtained in exchange for operating and finance lease liabilities	$	29	$	11

17. Subsequent Events

On October 12, 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 November 12, 2021 to unitholders of record on October 29, 2021.

On the same date, 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 December 15, 2021 to unitholders of record on December 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 December 15, 2021 to unitholders of record on December 1, 2021. The Series C distribution will be paid on January 18, 2022 to unitholders of record on January 3, 2022.

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

We anticipate our business will continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Our business is impacted by commodity prices and volumes. We mitigate a significant portion of commodity price risk on an overall Partnership basis 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 rebounded due to increasing demand and tightening supply from the lows seen at the start of the pandemic. However domestic exploration, development and production remain limited and our natural gas throughput and NGL volumes continue to be impacted.

The pandemic caused by the COVID-19 virus and its variant strains ("COVID-19") disrupted the U.S. economy since the first quarter of 2020. We began to see improvement in demand for our natural gas and NGL products and services beginning late in the second half of 2020, which continued through the third quarter of 2021. Management continues to monitor the COVID-19 pandemic, however, the degree to which these factors will impact our business and our results of operations in 2021 and beyond remains uncertain and the related financial impact of any such disruption cannot be reasonably estimated at this time.

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 during 2021 and their response to changes to commodity prices and demand remain uncertain. As a result, we expect volumes to remain below 2019 levels, which will 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, and 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 in certain regions. Certain counterparty billings during this time remain under dispute and are taking 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 future commodity price volatility as a result of the following:

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

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

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

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

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

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

During 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.

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

Results of Operations

Consolidated Overview

The following table and discussion provides a summary of our consolidated results of operations for the three and nine months ended September 30, 2021 and 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


		Three Months Ended September 30,				Nine Months Ended September 30,				Variance Three Months 2021 vs. 2020					Variance Nine Months 2021 vs. 2020
		2021		2020		2021		2020			Increase (Decrease)		Percent			Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues (a):
Logistics and Marketing		$	2,668	$	1,438	$	6,683	$	3,946		$	1,230	86	%		$	2,737	69	%
Gathering and Processing		1,821		857		4,449		2,388			964		*			2,061		86	%
Inter-segment eliminations		(1,662)		(709)		(3,902)		(1,817)			953		*			2,085		*
Total operating revenues		2,827		1,586		7,230		4,517			1,241		78	%		2,713		60	%
Purchases and related costs
Logistics and Marketing		(2,633)		(1,350)		(6,605)		(3,678)			1,283		95	%		2,927		80	%
Gathering and Processing		(1,540)		(577)		(3,684)		(1,477)			963		*			2,207		*
Inter-segment eliminations		1,662		709		3,902		1,817			953		*			2,085		*
Total purchases		(2,511)		(1,218)		(6,387)		(3,338)			1,293		*			3,049		91	%
Operating and maintenance expense		(168)		(146)		(482)		(447)			22		15	%		35		8	%
Depreciation and amortization expense		(89)		(92)		(273)		(284)			(3)		(3)	%		(11)		(4	%)
General and administrative expense		(63)		(66)		(158)		(173)			(3)		(5	%)		(15)		(9	%)
Asset impairments		—		—		(20)		(746)			—		—	%		(726)		*
Other (expense) income, net		(2)		(4)		4		(12)			(2)		(50)	%		(16)		*
Loss on sale of assets, net		—		—		(1)		—			—		—	%		1		*
Restructuring costs		—		—		—		(9)			—		—	%		(9)		*

Earnings from unconsolidated affiliates (b)		134		130		393		331			4		3	%		62		19	%
Interest expense		(73)		(77)		(227)		(226)			(4)		(5	%)		1		—	%
Income tax expense		—		(1)		—		(2)			(1)		*			(2)		*
Net income attributable to noncontrolling interests		(1)		(1)		(3)		(3)			—		—	%		—		—	%
Net income (loss) attributable to partners		$	54	$	111	$	76	$	(392)		$	(57)	(51)	%		$	468	*
Other data:
Adjusted gross margin (c):
Logistics and Marketing		$	35	$	88	$	78	$	268		$	(53)	(60	%)		$	(190)	(71	%)
Gathering and Processing		281		280		765		911			1		—	%		(146)		(16	%)
Total adjusted gross margin		$	316	$	368	$	843	$	1,179		$	(52)	(14	%)		$	(336)	(28	%)

Non-cash commodity derivative mark-to-market		$	(107)	$	(11)	$	(296)	$	66		$	(96)	*			$	(362)	*
NGL pipelines throughput (MBbls/d) (d)		668		680		639		678			(12)		(2	%)		(39)		(6	%)
Gas pipelines throughput (TBtu/d) (d)		1.08		1.05		1.04		0.85			0.03		3	%		0.19		22	%
Natural gas wellhead (MMcf/d) (d)		4,221		4,364		4,212		4,597			(143)		(3	%)		(385)		(8	%)
NGL gross production (MBbls/d) (d)		406		406		392		394			—		—	%		(2)		(1	%)

* Percentage change is not meaningful.

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

(b) 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.

(c) 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”.

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

Three Months Ended September 30, 2021 vs. Three Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $1,241 million in 2021 compared to 2020 primarily as a result of the following:

•$1,230 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 gas and NGL volumes and unfavorable commodity derivative activity; and

•$964 million increase for our Gathering and Processing segment primarily due to higher commodity prices, an increase in transportation, processing, other, and increased volumes in the DJ Basin, partially offset by unfavorable commodity derivative activity, and lower volumes in the South, Permian, and Midcontinent regions.

These increases were partially offset by:

•$953 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 $1,293 million in 2021 compared to 2020 primarily as a result of the following:

•$1,283 million increase for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$963 million increase for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These increases were partially offset by:

•$953 million change in inter-segment eliminations, for the reasons discussed above.

Operating and Maintenance Expense —Operating and maintenance expense increased in 2021 compared to 2020, as a result of increased base operating and maintenance costs primarily in the Permian region, and timing of reliability spend.

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

Adjusted Gross Margin — Adjusted Gross margin decreased $52 million in 2021 compared to 2020 primarily as a result of the following:

•$53 million decrease for our Logistics and Marketing segment primarily related to unfavorable commodity derivative activity and decrease of NGL marketing margins, partially offset by an increase in NGL pipeline margins.

This decrease was partially offset by:

•$1 million increase for our Gathering and Processing segment primarily due to higher commodity prices and increased volumes in the DJ Basin, partially offset by unfavorable commodity derivative activity, lower volumes in the South region, and lower Gathering and Processing margins.

Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $2,713 million in 2021 compared to 2020, primarily as a result of the following:

•$2,737 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 gas and NGL volumes, and unfavorable commodity derivative activity; and

•$2,061 million increase for our Gathering and Processing segment, primarily due to higher commodity prices, an increase in transportation, processing and other, and increased volumes in the DJ Basin, partially offset by unfavorable commodity derivative activity, and lower volumes in the South, Midcontinent, and Permian regions.

These increases were partially offset by:

•$2,085 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.

Total Purchases — Total purchases increased $3,049 million in 2021 compared to 2020, primarily as a result of the following:

•$2,927 million increase for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$2,207 million increase for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These increases were partially offset by:

•$2,085 million change in inter-segment eliminations, for the reasons discussed above.

Asset Impairments — Asset impairments in 2021 relate to long-lived assets in the Midcontinent region of our Gathering and Processing segment and the Logistics and Marketing segment. Asset impairments in 2020 relate to long-lived assets in the Permian and South regions and goodwill related to our North region.

Other (Expense) Income — Other income in 2021 was primarily a result of a contractual settlement. Other expense in 2020 was primarily related to asset write-offs and pipeline linefill adjustments.

Restructuring Costs — Restructuring costs decreased in 2021 compared to 2020 primarily as a result of our reduction in force in the second quarter of 2020.

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.

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

Adjusted Gross Margin — Adjusted gross margin decreased $336 million in 2021 compared to 2020, primarily as a result of the following:

•$190 million decrease for our Logistics and Marketing segment, primarily related to decrease of gas pipeline marketing margins due to less favorable commodity spreads, and a decrease related to Winter Storm Uri, which adversely impacted our gas marketing pipeline assets, partially offset by an increase in gas pipeline and storage marketing margins due to more favorable commodity spreads, and an increase in NGL pipeline margins; and

•$146 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 volumes in the South, Permian, and Midcontinent regions, lower gathering and processing margins, and the negative impact of Winter Storm Uri resulting in producer shut-ins, partially offset by higher commodity prices, and higher volumes in the DJ Basin.

Gas Pipelines Throughput — Gas throughput increased in 2021 compared to 2020, primarily as a result of increased volumes on the Cheyenne Connector pipeline.

Supplemental Information on Unconsolidated Affiliates

The following tables present financial information related to unconsolidated affiliates during the three and nine months ended September 30, 2021 and 2020, respectively:

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
DCP Sand Hills Pipeline, LLC	$	68	$	73	$	202	$	221
DCP Southern Hills Pipeline, LLC	21		19		67		59
Gulf Coast Express LLC	16		17		46		49
Front Range Pipeline LLC	10		9		28		29
Texas Express Pipeline LLC	5		4		14		13
Discovery Producer Services LLC (a)	2		(3)		13		(63)
Mont Belvieu 1 Fractionator	6		3		12		9
Mont Belvieu Enterprise Fractionator	2		4		1		10
Cheyenne Connector, LLC	4		3		8		3
Other	—		1		2		1
Total earnings from unconsolidated affiliates	$	134	$	130	$	393	$	331

(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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(millions)
DCP Sand Hills Pipeline, LLC	$	79	$	91	$	218	$	260
DCP Southern Hills Pipeline, LLC	30		28		85		76
Gulf Coast Express LLC	19		20		58		61
Front Range Pipeline LLC	10		12		32		38
Texas Express Pipeline LLC	5		6		16		17
Discovery Producer Services LLC	9		1		26		12
Mont Belvieu 1 Fractionator	5		3		11		10
Mont Belvieu Enterprise Fractionator	—		4		—		10
Cheyenne Connector, LLC	5		3		13		3
Other	1		1		3		2
Total distributions from unconsolidated affiliates	$	163	$	169	$	462	$	489

Results of Operations — Logistics and Marketing Segment


Operating Data
					Three Months Ended September 30, 2021		Nine Months Ended September 30, 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)	Pipeline Throughput (MBbls/d) (a)	Pipeline Throughput (TBtus/d) (a)
Sand Hills pipeline	1,400	—	333	—	285	—	267	—
Southern Hills pipeline	980	—	128	—	112	—	111	—

Front Range pipeline	450	—	87	—	65	—	60	—
Texas Express pipeline	600	—	37	—	18	—	20	—
Other NGL pipelines (a)	1,100	—	310	—	188	—	181	—
Gulf Coast Express pipeline	500	—	—	500	—	0.50	—	0.48
Guadalupe pipeline	600	—	—	245	—	0.28	—	0.26
Cheyenne Connector	70	—	—	300	—	0.30	—	0.30
Mont Belvieu fractionators	—	2	—	—	—	—	—	—
Pipelines total	5,700	2	895	1,045	668	1.08	639	1.04

(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 September 30,				Nine Months Ended September 30,				Variance Three Months 2021 vs. 2020					Variance Nine Months 2021 vs. 2020
	2021		2020		2021		2020			Increase (Decrease)		Percent			Increase (Decrease)		Percent

Operating revenues:
Sales of natural gas, NGLs and condensate	$	2,663	$	1,388	$	6,921	$	3,795		$	1,275	92	%		$	3,126	82	%
Transportation, processing and other	19		13		46		37			6		46	%		9		24	%
Trading and marketing (losses) gains, net	(14)		37		(284)		114			(51)		*			(398)		*
Total operating revenues	2,668		1,438		6,683		3,946			1,230		86	%		2,737		69	%
Purchases and related costs	(2,633)		(1,350)		(6,605)		(3,678)			1,283		95	%		2,927		80	%
Operating and maintenance expense	(11)		(8)		(29)		(24)			3		38	%		5		21	%
Depreciation and amortization expense	(3)		(3)		(9)		(9)			—		—	%		—		—	%
General and administrative expense	(1)		(1)		(4)		(4)			—		—	%		—		—	%
Asset impairments	—		—		(13)		—			—		—	%		13		*
Other (expense) income, net	—		(2)		5		(6)			(2)		*			(11)		*
Earnings from unconsolidated affiliates (a)	133		132		380		394			1		—	%		(14)		(4	%)

Segment net income attributable to partners	$	153	$	206	$	408	$	619		$	(53)	(26	%)		$	(211)	(34	%)
Other data:
Segment adjusted gross margin (b)	$	35	$	88	$	78	$	268		$	(53)	(60	%)		$	(190)	(71	%)
Non-cash commodity derivative mark-to-market	$	(7)	$	28	$	(47)	$	75		$	(35)	*			$	(122)	*
NGL pipelines throughput (MBbls/d) (c)	668		680		639		678			(12)		(2	%)		(39)		(6	%)
Gas pipelines throughput (TBtu/d) (c)	1.08		1.05		1.04		0.85			0.03		3	%		0.19		22	%

* 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 September 30, 2021 vs. Three Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $1,230 million in 2021 compared to 2020, primarily as a result of the following:

•$1,466 million increase as a result of higher commodity prices, which impacted both operating revenues and purchases, before the impact of derivative activity; and

•$6 million increase in transportation, processing and other.

These increases were partially offset by:

•$191 million decrease attributable to lower NGL and gas volumes; and

•$51 million decrease as a result of commodity derivative activity attributable to a $35 million increase in unrealized commodity derivative losses and a increase in realized cash settlement losses of $16 million due to movements in forward prices of commodities in 2021.

Purchases and Related Costs — Purchases and related costs increased $1,283 million in 2021 compared to 2020, for the reasons discussed above.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $53 million in 2021 compared to 2020, primarily as a result of the following:

•$51 million decrease as a result of commodity derivative activity as discussed above; and

•$7 million decrease as a result of NGL marketing margins.

These decreases were partially offset by:

•$5 million increase as a result of NGL pipeline margins.

Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $2,737 million in 2021 compared to 2020, primarily as a result of the following:

•$3,856 million increase as a result of higher commodity prices before the impact of derivative activity; and

•$9 million increase in transportation, processing and other.

These increases were partially offset by:

•$730 million decrease attributable to lower gas and NGL volumes; and

•$398 million decrease as a result of commodity derivative activity attributable to an increase in realized cash settlement losses of $276 million and an increase in unrealized commodity derivative losses of $122 million due to movements in forward prices of commodities.

Purchases and Related Costs — Purchases and related costs increased $2,927 million in 2021 compared to 2020, for the reasons discussed above.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2021 compared to 2020 due to an increase in pipeline integrity work in 2021 and focused cost reduction efforts in 2020.

Asset Impairments — Asset impairments in 2021 relate to long-lived assets in South Texas where we determined a triggering event occurred due to a negative outlook for long-term volume forecasts.

Other Income (Expense) — Other income in 2021 was primarily a result of a contractual settlement. Other expense in 2020 primarily relates to pipeline linefill adjustments.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $190 million in 2021 compared to 2020, primarily as a result of the following:

•$398 million decrease as a result of commodity derivative activity as discussed above, which includes an increase in unrealized derivatives losses of $122 million due to forward price movements of commodities in 2021; and

•$14 million decrease as a result of unfavorable 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, net of a large favorable offset at gas storage margins.

These decreases were partially offset by:

•$217 million increase as a result of increased gas pipeline and storage marketing margins due to more favorable commodity spreads in 2021; and

•$10 million increase as a result of NGL pipeline margins.

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 September 30, 2021		Nine Months Ended September 30, 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)	Natural Gas Wellhead Volume (MMcf/d) (a)	NGL Production (MBbls/d) (a)
North	13	3,500	1,580	1,567	145	1,542	142
Midcontinent	6	24,000	1,110	826	69	825	69
Permian	9	15,500	1,100	958	118	914	108
South	8	7,000	1,730	870	74	931	73
Total	36	50,000	5,520	4,221	406	4,212	392

(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 September 30,				Nine Months Ended September 30,				Variance Three Months 2021 vs. 2020					Variance Nine Months 2021 vs. 2020
		2021		2020		2021		2020			Increase (Decrease)		Percent			Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	1,854	$	786	$	4,518	$	2,052		$	1,068	*			$	2,466	*
Transportation, processing and other		126		97		342		294			29		30	%		48		16	%
Trading and marketing (losses) gains, net		(159)		(26)		(411)		42			(133)		*			(453)		*
Total operating revenues		1,821		857		4,449		2,388			964		*			2,061		86	%
Purchases and related costs		(1,540)		(577)		(3,684)		(1,477)			963		*			2,207		*
Operating and maintenance expense		(157)		(135)		(443)		(411)			22		16	%		32		8	%
Depreciation and amortization expense		(80)		(82)		(243)		(253)			(2)		(2)	%		(10)		(4	%)
General and administrative expense		(4)		(8)		(12)		(15)			(4)		(50)	%		(3)		(20	%)
Asset impairments		—		—		(7)		(746)			—		—	%		(739)		*
Other (expense) income, net		(2)		(2)		(1)		(4)			—		—	%		(3)		(75	%)
Loss on sale of assets, net		—		—		(1)		—			—		—	%		1		*
Earnings (loss) from unconsolidated affiliates (a)		1		(2)		13		(63)			3		*			76		*
Segment net income (loss)		39		51		71		(581)			(12)		(24	%)		652		*
Segment net income attributable to noncontrolling interests		(1)		(1)		(3)		(3)			—		—	%		—		—	%
Segment net income (loss) attributable to partners		$	38	$	50	$	68	$	(584)		$	(12)	(24	%)		$	652	*
Other data:
Segment adjusted gross margin (b)		$	281	$	280	$	765	$	911		$	1	—	%		$	(146)	(16	%)
Non-cash commodity derivative mark-to-market		$	(100)	$	(39)	$	(249)	$	(9)		(61)		*			$	(240)	*
Natural gas wellhead (MMcf/d) (c)		4,221		4,364		4,212		4,597			(143)		(3	%)		(385)		(8	%)
NGL gross production (MBbls/d) (c)		406		406		392		394			—		—	%		(2)		(1	%)

* 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 in the first quarter of 2020.

(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 September 30, 2021 vs. Three Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $964 million in 2021 compared to 2020, primarily as a result of the following:

•$1,107 million increase primarily due to higher commodity prices, which impacted both operating revenues and purchases, before the impact of derivative activity; and

•$29 million increase in transportation, processing and other.

These increases were partially offset by:

•$133 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $61 million due to movements in forward prices of commodities in 2021 and an increase in realized cash settlement losses of $72 million; and

•$39 million decrease as a result of lower volumes in the South, Permian, and Midcontinent regions, partially offset by increased volumes in the DJ Basin.

Purchases and Related Costs — Purchases and related costs increased $963 million in 2021 compared to 2020, as a result of the commodity price and volume changes discussed above.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2021 compared to 2020, as a result of increased base operating and maintenance costs primarily in the Permian region, and timing of reliability spend.

Segment Adjusted Gross Margin — Segment adjusted gross margin increased $1 million in 2021 compared to 2020, primarily as a result of the following:

•$152 million increase as a result of higher commodity prices.

This increase were partially offset by:

•$133 million decrease as a result of commodity derivative activity as discussed above; and

•$18 million decrease as a result of decreased volumes in the South region, and lower gathering and processing margins, partially offset by higher volumes in the DJ Basin.

Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020

Total Operating Revenues — Total operating revenues increased $2,061 million in 2021 compared to 2020, primarily as a result of the following:

•$2,693 million increase attributable to higher commodity prices, before the impact of derivative activity; and

•$48 million increase in transportation, processing and other.

These increases were partially offset by:

•$453 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $240 million due to movements in forward prices of commodities in 2021 and an increase in realized cash settlement losses of $213 million; and

•$227 million decrease as a result of lower volumes in the South, Midcontinent, and Permian regions, partially offset by partially offset by increased volumes in the DJ Basin.

Purchases and Related Costs — Purchases and related costs increased $2,207 million in 2021 compared to 2020, primarily as a result of the commodity price and volume changes discussed above.

Asset Impairments — Asset impairments in 2021 relate to certain long lived assets in the Midcontinent region that were sold in July 2021. 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 $146 million in 2021 compared to 2020, primarily as a result of the following:

•$384 million decrease as a result of unfavorable commodity derivative activity attributable to our corporate equity hedge program; and

•$104 million decrease due to lower volumes in the South, Permian, and Midcontinent regions, and lower gathering and processing margins, partially offset by higher volumes in the DJ Basin; 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.

These decreases were partially offset by:

•$377 million increase as a result of higher commodity prices.

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

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 cash generated from these sources 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 believe that commodity prices will remain volatile due to increasing demand and continued tight supply and volumes may continue to be depressed in the near term. 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 from the COVID-19 pandemic and reduce our debt, our leverage may increase as a result of the current economic environment.

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 September 30, 2021, we had unused borrowing capacity of $846 million, net of $552 million of outstanding borrowings and $2 million of letters of credit, under the Credit Agreement, of which at least $846 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. As of October 29, 2021, we had unused borrowing capacity of $1,045 million, net of $343 million of outstanding borrowings and $12 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 September 30, 2021, we had $350 million of outstanding borrowings under our Securitization Facility at LIBOR market index rates plus a margin. On August 2, 2021 we entered into an amendment to our Securitization Facility to extend the term of the facility until August 12, 2024. The amendment also includes Environmental, Social, and Governance linked Key Performance Indicators that increase or decrease certain fees based on our

safety performance relative to our peers, and year-over-year change in our greenhouse gas emissions intensity rate. The Securitization Facility provides for up to $350 million borrowing capacity at LIBOR market interest 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 number 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 nine months ended September 30, 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 September 30, 2021 and December 31, 2020, respectively;

•Balances related to debt of $5.330 billion and $5.273 billion as of September 30, 2021 and December 31, 2020, respectively; and

•Interest expense, net of $72 million and $75 million for the three months ended September 30, 2021 and 2020, respectively, and $224 million and $221 million for the nine months ended September 30, 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. Higher commodity prices during the period increased the amounts of collateral the Company was required to post at September 30, 2021.

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 regional 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 are taking longer to collect than normal, which have negatively impacted working capital at September 30, 2021. We believe the amounts due to us are owed and are vigorously pursuing legal avenues to collect these receivables.

We had working capital deficits of $285 million and $613 million as of September 30, 2021 and December 31, 2020, respectively, driven by current maturities of long term debt of $355 million and $505 million, respectively. We had a net derivative working capital deficit of $180 million as of September 30, 2021 and surplus of $7 million as of December 31, 2020.

As of September 30, 2021, we had $3 million in cash and cash equivalents, of which $2 million was held by consolidated subsidiaries we do not wholly own.

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


	Nine Months Ended September 30,
	2021		2020
	(millions)
Net cash provided by operating activities	$	255	$	791
Net cash used in investing activities	$	(73)	$	(225)
Net cash used in financing activities	$	(235)	$	(550)

Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020

Operating Activities — Net cash provided by operating activities decreased $536 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. At September 30, 2021 a substantial portion of this is due to increased collateral cash deposits to fund margin requirements on open positions on commodities exchanges that we enter into to mitigate a portion of our natural gas and NGL price risk. During February 2021, Winter Storm Uri resulted in lower regional 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 are taking longer to collect than normal. 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 $152 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 $315 million in 2021 compared to the same period in 2020, primarily as a result of higher distributions in the first quarter of 2020 and higher net payments of debt during the third quarter of 2020.

Contractual Obligations — Material contractual obligations arising in the normal course of business primarily consist of purchase obligations, long-term debt and related interest payments, leases, and other long-term liabilities. See Notes 9 and 10 to the Condensed Consolidated Financial Statements included in Item 1 "Financial Statements" for amounts outstanding on September 30, 2021, related to debt and leases.

Purchase Obligations are contractual obligations and include various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including gas supply, fractionation and transportation agreements in the ordinary course of business.

Management believes that our cash and investment position and operating cash flows as well as capacity under existing and available credit agreements will be sufficient to meet our liquidity and capital requirements for the foreseeable future. We believe that our current and projected asset position is sufficient to meet our liquidity requirements.

Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. We may enter into purchase order and non-cancelable construction agreements for capital expenditures. 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 $244 million and $325 million during the nine months ended September 30, 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.”

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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Reconciliation of Non-GAAP Measures	(millions)

Reconciliation of gross margin to adjusted gross margin:

Operating revenues	$	2,827	$	1,586	$	7,230	$	4,517
Cost of revenues
Purchases and related costs	2,181		944		5,484		2,539
Purchases and related costs from affiliates	81		32		183		89
Transportation and related costs from affiliates	249		242		720		710
Depreciation and amortization expense	89		92		273		284
Gross margin	227		276		570		895
Depreciation and amortization expense	89		92		273		284
Adjusted gross margin	$	316	$	368	$	843	$	1,179



Reconciliation of segment gross margin to segment adjusted gross margin:

Logistics and Marketing segment:
Operating revenues	$	2,668	$	1,438	$	6,683	$	3,946
Cost of revenues
Purchases and related costs	2,633		1,350		6,605		3,678
Depreciation and amortization expense	3		3		9		9
Segment gross margin	32		85		69		259
Depreciation and amortization expense	3		3		9		9
Segment adjusted gross margin	$	35	$	88	$	78	$	268



Gathering and Processing segment:
Operating revenues	$	1,821	$	857	$	4,449	$	2,388
Cost of revenues
Purchases and related costs	1,540		577		3,684		1,477
Depreciation and amortization expense	80		82		243		253
Segment gross margin	201		198		522		658
Depreciation and amortization expense	80		82		243		253
Segment adjusted gross margin	$	281	$	280	$	765	$	911


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		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)	$	153	$	206	$	408	$	619
Non-cash commodity derivative mark-to-market	7		(28)		47		(75)
Depreciation and amortization expense, net of noncontrolling interest	3		3		9		9
Distributions from unconsolidated affiliates, net of earnings	21		35		56		82

Asset impairments	—		—		13		—
Other expense	—		—		—		2
Adjusted segment EBITDA	$	184	$	216	$	533	$	637

Gathering and Processing segment:
Segment net income (loss) attributable to partners	$	38	$	50	$	68	$	(584)
Non-cash commodity derivative mark-to-market	100		39		249		9
Depreciation and amortization expense, net of noncontrolling interest	80		82		241		252
Asset impairments	—		—		7		746

Distributions from unconsolidated affiliates, net of earnings	8		4		13		76
Other expense	1		1		2		3
Adjusted segment EBITDA	$	227	$	176	$	580	$	502

(a) We recognized no lower of cost or net realizable value adjustment for the three and nine months ended September 30, 2021, respectively. We recognized $6 million of lower of cost or net realizable value adjustments for the nine months ended September 30, 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 and nine months ended September 30, 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 October 29, 2021 were as follows:

Commodity Swaps

Period

Commodity

Notional
Volume
- Short
Positions

Reference Price

Price Range

October 2021 — December 2022

Natural Gas

(138,500) MMBtu/d (e)

NYMEX Final Settlement Price (a)

$2.35-$5.90/MMBtu

January 2023 — December 2023

Natural Gas

(17,500) MMBtu/d (e)

NYMEX Final Settlement Price (a)

$2.80-$5.90/MMBtu

October 2021 — December 2021

NGLs

(11,416) Bbls/d (d)

Mt.Belvieu (b)

$0.53-$0.68/Gal

January 2022 — December 2022

NGLs

(9,378) Bbls/d (d)

Mt.Belvieu (b)

$0.54-$0.94/Gal

October 2021 — February 2022

Crude Oil

(5,949) Bbls/d (d)

NYMEX crude oil futures (c)

$45.46-$65.56/Bbl

March 2022 — February 2023

Crude Oil

(2,877) Bbls/d (d)

NYMEX crude oil futures (c)

$46.86-$65.56/Bbl

March 2023 — December 2023

Crude Oil

(981) Bbls/d (d)

NYMEX crude oil futures (c)

$60.37-$60.79/Bbl

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

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

(d) Average Bbls/d per time period.

(e) Average MMBtu/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 September 30, 2021:

Inventory

Period ended

Commodity

Notional Volume - Long
Positions

Fair Value
(millions)

Weighted
Average Price

September 30, 2021

Natural Gas

9,754,061

MMBtu

$3.00/MMBtu

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long
Positions

Fair Value
(millions)

Price Range

October 2021 — December 2021

Natural Gas

(21,762,500)

MMBtu

(37)

$2.74-$5.89/MMBtu

October 2021

Natural Gas

12,262,500

MMBtu

$2.84-$5.86/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 September 30, 2021:

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long Positions

Fair Value (millions)

Price Range (a)

October 2021 — December 2025

Natural Gas

(83,012,500)

MMBtu

$(11)

$0.05-$0.52/MMBtu

October 2021 — September 2026

Natural Gas

79,827,500

MMBtu

$0.40-$1.61/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 September 30, 2021, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of September 30, 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 September 30, 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.

Item 5. Other Information

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On November 1, 2021, William Johnson, age 50, was appointed as President, Operations, of DCP Midstream GP, LLC (the “Company”), which is the general partner of the general partner of DCP Midstream, LP (the “Partnership”).

Prior to this appointment, Mr. Johnson served as group vice president and chief transformation officer for the Company since January 2017 where he was responsible for engineering, projects, information technology, operations technology, digital solutions, and the Company's integrated collaboration center. Prior to that, Mr. Johnson served as vice president of operations for the North and Permian regions. He previously also served as the vice president of technical services, responsible for regional engineering, corporate reliability, compression services, and measurement. Before joining the Company in 2011, Mr. Johnson held management positions in project engineering, operations, reliability and maintenance, turnarounds, corporate

engineering, and plant management at multiple chemical and refining plant sites as well as at corporate headquarters for Arco Chemical, Lyondell, and LyondellBasell.

In connection with this appointment, Mr. Johnson will receive an annual base salary of $425,000. In addition, Mr. Johnson will receive an annual short-term cash incentive under DCP Services LLC’s short-term incentive program with a target of 70% of his base salary, and an annual grant of strategic performance units and restricted phantom units under the Partnership’s 2016 Long-Term Incentive Plan with a target of 190% of his base salary.

There are no arrangements or understandings between Mr. Johnson and any other person pursuant to which he was appointed to serve as President, Operations, of the Company. Mr. Johnson does not have any family relationships with any of the Company’s directors or executive officers. Since the beginning of the Partnership's last fiscal year, Mr. Johnson and his immediate family members do not have any direct or indirect material interest in any existing or proposed transaction, arrangement, or relationship with the Company or the Partnership or any director or executive officer of the Company or immediate family member thereof in which the amount involved exceeds $120,000.

Item 6. Exhibits


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		Fourth Amendment to Receivables Financing Agreement, dated August 2, 2021, among DCP Receivables LLC, as borrower, DCP Midstream, LP, as initial servicer, the lenders, LC participants and group agents that are parties thereto from time to time, PNC Bank National Association, as Administrative Agent and LC Bank and PNC Capital Markets LLC, as Structuring Agent (attached as Exhibit 10.5 to DCP Midstream, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on August 4, 2021).
22		List of Guaranteed Securities
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream, LP for the three and nine months ended September 30, 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: November 3, 2021

By:

/s/ Wouter T. van Kempen

Name:

Wouter T. van Kempen

Title:

President and Chief Executive Officer

(Principal Executive Officer)

Date: November 3, 2021

By:

/s/ Sean P. O'Brien

Name:

Sean P. O'Brien

Title:

Group Vice President and Chief Financial Officer

(Principal Financial Officer)