DCP Midstream, LP - Quarter Report: 2023 June (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 June 30, 2023


¨			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.)

6900 E. Layton Ave, Suite 900 Denver, Colorado						80237
(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

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 July 28, 2023, there were 208,677,458 common units representing limited partnership interests outstanding.

DCP MIDSTREAM, LP

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2023

TABLE OF CONTENTS



Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of June 30, 2023 and December 31, 2022	2
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2023 and 2022	3
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2023 and 2022	4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2023 and 2022	5
	Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2023	6
	Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2022	7
	Notes to the Condensed Consolidated Financial Statements	8
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
3.	Quantitative and Qualitative Disclosures about Market Risk	47
4.	Controls and Procedures	49
	PART II. OTHER INFORMATION
1.	Legal Proceedings	50
1A	Risk Factors	50

5.	Other Information	50
6.	Exhibits	50
	Signatures	52

GLOSSARY OF TERMS

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



ASU						accounting standards update
Bbl						barrel
Bbls/d						barrels per day


Btu						British thermal unit, a measurement of energy

Credit Agreement						Credit Agreement governing our Credit Facility
Credit Facility						Our $1.4 billion unsecured revolving credit facility, maturing March 18, 2027

DCP Receivables						DCP Receivables LLC
Fractionation						the process by which natural gas liquids are separated into individual components
GAAP						generally accepted accounting principles in the United States of America


Intercompany Credit Agreement						Intercompany Credit Agreement with Phillips 66

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




SEC						U.S. Securities and Exchange Commission
Securitization Facility						$350 million Accounts Receivable Securitization Facility, maturing August 12, 2024
SOFR						Secured Overnight Financing Rate
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” and can be identified 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 current 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 these 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 our Annual Report on Form 10-K for the year ended December 31, 2022, including the following risks and uncertainties:

•conflicts of interest may exist between our individual Series C preferred unitholders and Phillips 66, which has the authority to conduct, direct and manage the activities of DCP Midstream, LLC associated with the Partnership and our general partner;

•risks related to the disruption of 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;

•other factors beyond our control including the increased cost of labor, contractors, services, supplies and materials due to persistent inflation;

•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 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;

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

iii

•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 to execute our business strategy;

•the success of our ongoing integration with Phillips 66;

•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 our 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.

PART I

Item 1. Financial Statements

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)


	June 30, 2023		December 31, 2022
ASSETS	(millions)
Current assets:
Cash and cash equivalents	$	5	$	1


Accounts receivable:
Trade, net of allowance for credit losses of $3 and $2 million, respectively	438		995
Affiliates	425		360
Other	2		3
Inventories	41		83
Unrealized gains on derivative instruments	60		140

Collateral cash deposits	3		93
Other	28		27
Total current assets	1,002		1,702
Property, plant and equipment, net	7,733		7,763

Intangible assets, net	32		34
Investments in unconsolidated affiliates	3,416		3,475
Unrealized gains on derivative instruments	17		26
Operating lease assets	109		112
Other long-term assets	183		222
Total assets	$	12,492	$	13,334
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	517	$	1,199
Affiliates	253		255
Other	30		29

Current debt	7		506
Unrealized losses on derivative instruments	36		148
Accrued interest	71		78
Accrued taxes	51		58
Accrued wages and benefits	32		72
Capital spending accrual	8		22

Other	139		137
Total current liabilities	1,144		2,504
Long-term debt	4,901		4,357
Long-term debt - related party	100		—
Unrealized losses on derivative instruments	13		35
Deferred income taxes	33		33
Operating lease liabilities	97		95
Other long-term liabilities	221		274
Total liabilities	6,509		7,298
Commitments and contingent liabilities (see note 13)
Equity:

Series B preferred limited partners (0 and 6,450,000 preferred units authorized, issued and outstanding, respectively)	—		156
Series C preferred limited partners (4,400,000 preferred units authorized, issued and outstanding, respectively)	106		106

Limited partners (208,677,458 and 208,396,558 common units authorized, issued and outstanding, respectively)	5,859		5,755
Accumulated other comprehensive loss	(6)		(6)
Total partners’ equity	5,959		6,011
Noncontrolling interests	24		25
Total equity	5,983		6,036
Total liabilities and equity	$	12,492	$	13,334

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	762	$	2,880	$	2,505	$	5,208
Sales of natural gas, NGLs and condensate to affiliates	911		1,219		1,644		2,346
Transportation, processing and other	148		184		311		339
Trading and marketing gains (losses), net	20		(14)		107		(249)

Total operating revenues	1,841		4,269		4,567		7,644
Operating costs and expenses:
Purchases and related costs	1,112		3,269		2,964		5,988
Purchases and related costs from affiliates	12		100		109		199
Transportation and related costs from affiliates	288		275		567		532
Operating and maintenance expense	229		189		426		341
Depreciation and amortization expense	91		90		181		180
General and administrative expense	68		65		148		120

Asset impairments	—		1		—		1
Other income, net	—		(8)		—		(8)
Loss (gain) on sale of assets, net	3		—		3		(7)
Restructuring costs	16		—		26		—
Total operating costs and expenses	1,819		3,981		4,424		7,346
Operating income	22		288		143		298

Earnings from unconsolidated affiliates	148		168		308		311
Interest expense, net	(75)		(70)		(143)		(141)
Income before income taxes	95		386		308		468
Income tax expense	—		(2)		(1)		(3)
Net income	95		384		307		465
Net income attributable to noncontrolling interests	(1)		(1)		(2)		(2)
Net income attributable to partners	94		383		305		463

Series A preferred limited partners' interest in net income	—		(9)		—		(18)
Series B preferred limited partners' interest in net income	(3)		(3)		(6)		(6)
Series C preferred limited partners' interest in net income	(2)		(3)		(4)		(5)

Redemption of Series B preferred limited partners' units	(5)		—		(5)		—

Net income allocable to limited partners	$	84	$	368	$	290	$	434
Net income per limited partner unit — basic and diluted	$	0.40	$	1.77	$	1.39	$	2.08

Weighted-average limited partner units outstanding — basic	208.7		208.4		208.6		208.4
Weighted-average limited partner units outstanding — diluted	208.7		208.5		208.6		208.6

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
Net income	$	95	$	384	$	307	$	465
Other comprehensive income:


Total other comprehensive income	—		—		—		—
Total comprehensive income	95		384		307		465
Total comprehensive income attributable to noncontrolling interests	(1)		(1)		(2)		(2)
Total comprehensive income attributable to partners	$	94	$	383	$	305	$	463

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Six Months Ended June 30,
	2023		2022
	(millions)
OPERATING ACTIVITIES:
Net income	$	307	$	465
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	181		180
Earnings from unconsolidated affiliates	(308)		(311)
Distributions from unconsolidated affiliates	360		369
Net unrealized (gains) losses on derivative instruments	(47)		75

Asset impairments	—		1
Loss (gain) on sale of assets, net	3		(7)

Other, net	39		14
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable	492		(624)
Inventories	20		(31)
Accounts payable	(693)		606



Other assets and liabilities	15		(163)
Net cash provided by operating activities	369		574
INVESTING ACTIVITIES:
Capital expenditures	(163)		(60)

Acquisition	—		(16)
Investments in unconsolidated affiliates	(1)		(1)
Distribution from unconsolidated affiliate	9		—
Proceeds from sale of assets	4		16

Net cash used in investing activities	(151)		(61)
FINANCING ACTIVITIES:
Proceeds from debt	2,576		2,690
Payments of debt	(2,441)		(2,998)






Distributions to preferred limited partners	(10)		(29)

Distributions to limited partners and general partner	(179)		(163)
Distributions to noncontrolling interests	(3)		(2)
Redemption of preferred shares	(161)		—
Debt issuance costs	—		(4)



Net cash used in financing activities	(218)		(506)
Net change in cash, cash equivalents and restricted cash	—		7
Cash, cash equivalents and restricted cash, beginning of period	5		1
Cash, cash equivalents and restricted cash, end of period	$	5	$	8

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)


	Partner's Equity
	Series B Preferred Limited Partners		Series C Preferred Limited Partners		Limited Partners		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total Equity
	(millions)
Balance, January 1, 2023	$	156	$	106	$	5,755	$	(6)	$	25	$	6,036
Net income	3		2		206		—		1		212
Distributions to unitholders	(3)		(2)		(90)		—		—		(95)
Distributions to noncontrolling interests	—		—		—		—		(2)		(2)
Equity based compensation	—		—		(3)		—		—		(3)

Balance, March 31, 2023	$	156	$	106	$	5,868	$	(6)	$	24	$	6,148
Net income	3		2		89		—		1		95

Redemption of Series B preferred limited partners' units	(156)		—		(5)		—		—		(161)
Distributions to unitholders	(3)		(2)		(89)		—		—		(94)
Distributions to noncontrolling interests	—		—		—		—		(1)		(1)
Equity based compensation	—		—		(4)		—		—		(4)
Balance, June 30, 2023	$	—	$	106	$	5,859	$	(6)	$	24	$	5,983

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, 2022	$	489	$	156	$	106	$	5,106	$	(6)	$	25	$	5,876
Net income	9		3		2		66		—		1		81
Distributions to unitholders	—		(3)		(2)		(81)		—		—		(86)
Distributions to noncontrolling interests	—		—		—		—		—		(1)		(1)
Equity based compensation	—		—		—		1		—		—		1
Balance, March 31, 2022	$	498	$	156	$	106	$	5,092	$	(6)	$	25	$	5,871
Net income	9		3		3		368		—		1		384


Distributions to unitholders	(18)		(3)		(3)		(82)		—		—		(106)
Distributions to noncontrolling interests	—		—		—		—		—		(1)		(1)
Equity based compensation	—		—		—		2		—		—		2
Balance, June 30, 2022	$	489	$	156	$	106	$	5,380	$	(6)	$	25	$	6,150

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

(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" in the Notes to the Condensed Consolidated Financial Statements in Item 1. "Financial Statements".

Our operations and activities are managed by our general partner, DCP Midstream GP, LP (“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. Phillips 66 has the authority to conduct, direct and manage the activities of DCP Midstream, LLC associated with the Partnership and our general partner, and, therefore, effectively controls our business and affairs.

On January 5, 2023, the Partnership, GP LP, the General Partner, Phillips 66, Phillips 66 Project Development Inc., a Delaware corporation and indirect wholly owned subsidiary of Phillips 66 (“PDI”), and Dynamo Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of PDI (“Merger Sub”), entered into an Agreement and Plan of Merger (the "Merger Agreement"), pursuant to which Merger Sub merged with and into the Partnership, with the Partnership surviving as a Delaware limited partnership (the “Merger”). The Merger was completed on June 15, 2023 in accordance with the terms of the Merger Agreement.

Under the terms of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each common unit representing a limited partner interest in the Partnership (each, a “Common Unit”) issued and outstanding as of immediately prior to the Effective Time (other than the Sponsor Owned Units, as defined below) (each, a “Public Common Unit”) was converted into the right to receive $41.75 per Public Common Unit in cash, without any interest thereon (the “Merger Consideration”). The Common Units owned by DCP Midstream, LLC and the General Partner (collectively, the “Sponsor Owned Units”) were unaffected by the Merger and remained outstanding immediately following the Merger as Common Units of the Partnership. Following the Merger, the Common Units were delisted from the New York Stock Exchange (“NYSE”) and a Form 15 has been filed to deregister the Common Units under the Securities Exchange Act of 1934, as amended.

As a result of the Merger, Phillips 66’s economic interest in the Partnership increased from 43.3% to approximately 86.8%. Enbridge's economic interest in the Partnership was unchanged, and remains at approximately 13.2%.

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. All intercompany balances and transactions have been eliminated in consolidation.

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 June 30, 2023
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	418	$	343	$	(321)	$	440
Sales of NGLs and condensate (a)	1,106		778		(651)		1,233
Transportation, processing and other	18		130		—		148
Trading and marketing gains (losses), net (b)	19		1		—		20
Total operating revenues	$	1,561	$	1,252	$	(972)	$	1,841

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022


	Six Months Ended June 30, 2023
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	1,220	$	1,023	$	(990)	$	1,253
Sales of NGLs and condensate (a)	2,634		1,676		(1,414)		2,896
Transportation, processing and other	37		274		—		311
Trading and marketing gains, net (b)	62		45		—		107
Total operating revenues	$	3,953	$	3,018	$	(2,404)	$	4,567

(a) Includes $444 million and $923 million for the three and six months ended June 30, 2023, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment. For the three and six months ended June 30, 2023, these revenues are net of $868 million and $1,593 million, respectively, of buy-sell purchases related to buy-sell revenues of $954 million and $1,751 million, respectively, which are not within the scope of Topic 606.

(b) Not within the scope of Topic 606.


	Three Months Ended June 30, 2022
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	1,436	$	1,238	$	(1,169)	$	1,505
Sales of NGLs and condensate (a)	2,333		1,579		(1,318)		2,594
Transportation, processing and other	18		166		—		184
Trading and marketing gains (losses), net (b)	2		(16)		—		(14)
Total operating revenues	$	3,789	$	2,967	$	(2,487)	$	4,269


	Six Months Ended June 30, 2022
	Logistics and Marketing		Gathering and Processing		Eliminations		Total
	(millions)
Sales of natural gas	$	2,499	$	2,120	$	(1,990)	$	2,629
Sales of NGLs and condensate (a)	4,455		2,861		(2,391)		4,925
Transportation, processing and other	37		302		—		339
Trading and marketing losses, net (b)	(39)		(210)		—		(249)
Total operating revenues	$	6,952	$	5,073	$	(4,381)	$	7,644

(a) Includes $708 million and $1,384 million for the three and six months ended June 30, 2022, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our Logistics and Marketing segment. For the three and six months ended June 30, 2022, these revenues are net of $1,005 million and $1,761 million, respectively, of buy-sell purchases related to buy-sell revenues of $1,089 million and $1,940 million, respectively, 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 $349 million as of June 30, 2023. 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 three years as of June 30, 2023. 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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

3. Agreements and Transactions with Affiliates

Phillips 66 Intercompany Credit Agreement

We entered into an Intercompany Credit Agreement with Phillips 66 on June 15, 2023. For more information regarding the terms and conditions of the Intercompany Credit Agreement, see Note 8 "Debt" in the Notes to the Condensed Consolidated Financial Statements in Item 1. "Financial Statements".

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense	$	46	$	42	$	89	$	82
General and administrative expense	$	29	$	42	$	87	$	75
Restructuring costs	$	16	$	—	$	26	$	—

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:


	Three Months Ended June 30,					Six Months Ended June 30,
	2023		2022			2023		2022
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	896	$	1,197	1197	$	1,600	$	2,292
Purchases and related costs from affiliates	$	2	$	65		$	77	$	127
Transportation and related costs from affiliates	$	46	$	47		$	87	$	90
Operating and maintenance and general administrative expenses	$	6	$	4		$	10	$	7
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	1	$	(2)		$	2	$	(2)
Purchases and related costs from affiliates	$	—	$	—		$	—	$	13
Transportation and related costs from affiliates	$	1	$	1		$	1	$	1
Operating and maintenance and general administrative expenses	$	1	$	—		$	1	$	—
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	14	$	24		$	42	$	56
Transportation, processing, and other to affiliates	$	4	$	3		$	8	$	7
Purchases and related costs from affiliates	$	10	$	35		$	32	$	59
Transportation and related costs from affiliates	$	241	$	227		$	479	$	441

We had balances with affiliates as follows:


	June 30, 2023		December 31, 2022
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	398	$	343
Other assets	$	7	$	1
Accounts payable	$	163	$	167
Accrued wages and benefits	$	32	$	—
Other liabilities	$	28	$	—
Long-term debt	$	100	$	—
Enbridge (including its affiliates):
Accounts receivable	$	—	$	1
Accounts payable	$	—	$	1


Unconsolidated affiliates:
Accounts receivable	$	27	$	16
Accounts payable	$	90	$	87

4. Inventories

Inventories were as follows:


	June 30, 2023		December 31, 2022
	(millions)
Natural gas	$	20	$	47
NGLs	21		36
Total inventories	$	41	$	83

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

We recognize the 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 zero and $22 million lower of cost or net realizable value adjustments for the three and six months ended June 30, 2023, respectively. We recognized no lower of cost or net realizable value adjustments for the three and six months ended June 30, 2022.

5. Property, Plant and Equipment

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


	Depreciable Life	June 30, 2023		December 31, 2022
		(millions)
Gathering and transmission systems	20 — 50 Years	$	7,955	$	7,865
Processing, storage and terminal facilities	35 — 60 Years	5,175		5,138
Other	3 — 30 Years	545		563
Finance lease assets	5 — 35 Years	32		32
Construction work in progress		196		183
Property, plant and equipment		13,903		13,781
Accumulated depreciation		(6,170)		(6,018)
Property, plant and equipment, net		$	7,733	$	7,763

Construction projects with capitalized interest were immaterial during the six months ended June 30, 2023 and 2022.

Depreciation expense was $90 million and $88 million for the three months ended June 30, 2023 and 2022, respectively, and $179 million and $177 million for the six months ended June 30, 2023 and 2022, respectively.

6. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:


		Carrying Value as of
	Percentage Ownership	June 30, 2023		December 31, 2022
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,637	$	1,653
DCP Southern Hills Pipeline, LLC	66.67%	705		713
Gulf Coast Express LLC	25.00%	392		408
Front Range Pipeline LLC	33.33%	187		191
Texas Express Pipeline LLC	10.00%	88		91
Mont Belvieu 1 Fractionator	20.00%	9		7
Discovery Producer Services LLC	40.00%	208		219
Cheyenne Connector, LLC	50.00%	141		143
Mont Belvieu Enterprise Fractionator	12.50%	28		28


Other	Various	21		22
Total investments in unconsolidated affiliates		$	3,416	$	3,475

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	104	$	165	$	175
DCP Southern Hills Pipeline, LLC	27		21		52		45
Gulf Coast Express LLC	18		16		35		32
Front Range Pipeline LLC	11		11		22		21
Texas Express Pipeline LLC	5		5		10		10
Mont Belvieu 1 Fractionator	4		3		8		7
Discovery Producer Services LLC	1		3		7		9
Cheyenne Connector, LLC	3		3		6		7
Mont Belvieu Enterprise Fractionator	1		2		2		4

Other	—		—		1		1
Total earnings from unconsolidated affiliates	$	148	$	168	$	308	$	311

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)				(millions)
Statements of operations:
Operating revenue	$	541	$	626	$	1,136	$	1,189
Operating expenses	$	214	$	246	$	436	$	463
Net income	$	328	$	380	$	707	$	724

7. Fair Value Measurement

Valuation Hierarchy

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

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

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

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

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

Commodity Derivative Assets and Liabilities

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

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.

The following table presents the financial instruments carried at fair value on a recurring basis as of June 30, 2023 and December 31, 2022, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:


	June 30, 2023								December 31, 2022
	Level 1		Level 2		Level 3		Total Carrying Value		Level 1		Level 2		Level 3		Total Carrying Value
	(millions)
Current assets:
Commodity derivatives	$	1	$	49	$	10	$	60	$	2	$	121	$	17	$	140
Short-term investments (a)	$	—	$	—	$	—	$	—	$	—	$	1	$	—	$	1

Long-term assets:
Commodity derivatives	$	—	$	16	$	1	$	17	$	—	$	23	$	3	$	26
Investments in marketable securities (a)	$	—	$	—	$	—	$	—	$	42	$	—	$	—	$	42
Current liabilities:
Commodity derivatives	$	(1)	$	(31)	$	(4)	$	(36)	$	(4)	$	(142)	$	(2)	$	(148)

Long-term liabilities:
Commodity derivatives	$	—	$	(12)	$	(1)	$	(13)	$	—	$	(32)	$	(3)	$	(35)

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

(a) zero and $1 million recorded within "Other" current assets and zero and $42 million recorded within "Other long-term assets" as of June 30, 2023 and December 31, 2022, respectively.

Changes in Level 3 Fair Value Measurements

The table below illustrates a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3.

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


	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Three months ended June 30, 2023 (a):
Beginning balance	$	15	$	1	$	(1)	$	(1)
Net unrealized gains (losses) included in earnings	6		—		(6)		(1)

Transfers out of Level 3	(9)		(1)		4		1
Settlements	(2)		1		(1)		—


Ending balance	$	10	$	1	$	(4)	$	(1)
Net unrealized gains (losses) on derivatives still held included in earnings	$	4	$	—	$	(3)	$	—
Three months ended June 30, 2022 (a):
Beginning balance	$	2	$	4	$	(10)	$	(5)
Net unrealized gains included in earnings	3		2		5		—

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


Ending balance	$	3	$	6	$	(3)	$	(4)
Net unrealized gains (losses) on derivatives still held included in earnings	$	3	$	3	$	5	$	(6)

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022


	Commodity Derivative Instruments
	Current Assets		Long-Term Assets		Current Liabilities		Long-Term Liabilities
	(millions)
Six months ended June 30, 2023 (a):
Beginning balance	$	17	$	3	$	(2)	$	(3)
Net unrealized gains (losses) included in earnings	5		—		(2)		1

Transfers out of Level 3	(8)		(2)		1		1
Settlements	(4)		—		(1)		—


Ending balance	$	10	$	1	$	(4)	$	(1)
Net unrealized gains (losses) on derivatives still held included in earnings	$	6	$	1	$	(3)	$	(1)
Six months ended June 30, 2022 (a):
Beginning balance	$	—	$	2	$	(3)	$	(4)
Net unrealized gains (losses) included in earnings	3		6		(6)		(6)

Transfers out of Level 3	—		(2)		4		6
Settlements	—		—		2		—


Ending balance	$	3	$	6	$	(3)	$	(4)
Net unrealized gains (losses) on derivatives still held included in earnings	$	3	$	4	$	(2)	$	(3)

(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three and six months ended June 30, 2023 and 2022.

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.

June 30, 2023

Product Group

Fair Value

Valuation Techniques

Unobservable Input

Forward
Curve Range

Weighted Average (a)

(millions)

Assets

NGLs

Market approach

Longer dated forward curve prices

$0.24-$1.29

$0.68

Per gallon

Natural gas

Market approach

Longer dated forward curve prices

$2.73-$4.71

$1.96

Per MMBtu

Liabilities

NGLs

(4)

Market approach

Longer dated forward curve prices

$0.24-$1.33

$0.81

Per gallon

Natural gas

(1)

Market approach

Longer dated forward curve prices

$2.73-$4.71

$3.16

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 long-lived assets and equity investments in unconsolidated affiliates. The inputs used to determine such fair value are primarily based upon internally developed cash flow

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

During the three and six months ended June 30, 2023, we recognized a $10 million impairment associated with an office lease that we vacated and partially sublet as part of our integration with Phillips 66 during the three months ended June 30, 2023. This impairment is recorded within restructuring costs in our condensed consolidated statements of operations and other, net within our condensed consolidated statements of cash flows.

Estimated Fair Value of Financial Instruments

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

We determine the fair value of our fixed-rate senior notes 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 June 30, 2023 and December 31, 2022, the carrying value and fair value of our total debt, including current maturities, were as follows:


		June 30, 2023				December 31, 2022
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)

Total debt		$	5,013	$	4,976	$	4,874	$	4,772

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

8. Debt

Junior Notes Redemption

On May 19, 2023, we redeemed, at par, prior to maturity all $550 million of aggregate principal amount outstanding of our 5.850% Junior Notes due May 2043, using borrowings under our Credit Facility and Securitization Facility.

Senior Notes Redemption

On March 15, 2023, we repaid, at par, all $500 million of aggregate principal amount outstanding of our 3.875% Senior Notes due March 15, 2023, using borrowings under our Credit Facility and Securitization Facility.

Intercompany Credit Agreement

On June 15, 2023, we and our wholly owned subsidiary, DCP Midstream Operating, LP, entered into a new five-year revolving Intercompany Credit Agreement with Phillips 66, as lender. The Intercompany Credit Agreement provides up to $1 billion of borrowing capacity, with an option to increase the commitment by an aggregate principal amount of up to $500 million, subject to lender approval. At our election, the Intercompany Credit Agreement bears interest at either the adjusted term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. A ratings-based pricing grid determines our cost of borrowing under the Intercompany Credit Agreement. Indebtedness under the Intercompany Credit Agreement bears interest at either: (1) SOFR, plus an applicable margin of 1.075% based on our current credit rating, plus an adjustment of 0.10%; or (2) (a) the base rate, which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the SOFR Market Index rate plus 1.00%, plus (b) an applicable margin of 0.075% based on our current credit rating. Based on our current credit rating, the Intercompany Credit Agreement incurs an annual facility fee of 0.175%.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

As of June 30, 2023, we had unused borrowing capacity of $900 million, net of $100 million of outstanding borrowings, under the Intercompany Credit Agreement, of which $900 million would have been available to borrow for working capital and other general partnership purposes based on the financial covenants set forth in the Intercompany Credit Agreement. Except in the case of a default, amounts borrowed under our Intercompany Credit Agreement will not become due prior to the June 15, 2028 maturity date.

Credit Agreement

We are party to a $1.4 billion unsecured revolving Credit Facility governed by the Credit Agreement that bears interest at either the term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. The Credit Agreement matures on March 18, 2027. The Credit Agreement also includes sustainability linked key performance indicators that increase or decrease the applicable margin and facility fee payable thereunder based on our safety performance relative to our peers and year-over-year change in our greenhouse gas emissions intensity rate.

As of June 30, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 million of letters of credit, under the Credit Agreement, of which $548 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 March 18, 2027 maturity date.

Accounts Receivable Securitization Facility

The Securitization Facility provides for up to $350 million of borrowing capacity through August 2024 at an adjusted SOFR rate and includes an uncommitted option to increase the total commitments under the Securitization Facility by up to an additional $400 million. 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, a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility.

As of June 30, 2023, DCP Receivables had approximately $785 million of our accounts receivable securing borrowings of $280 million under the Securitization Facility.

The maturities of our debt as of June 30, 2023 are as follows:


	Debt Maturities
	(millions)
2023	$	—
2024	280
2025	825
2026	—
2027	1,350
Thereafter	2,550
Total debt	$	5,005

9. 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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

Collateral

As of June 30, 2023, we had cash deposits of $3 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of June 30, 2023, we held letters of credit of $23 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.

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:


	June 30, 2023				December 31, 2022
	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	$	77	$	(8)	$	69	$	166	$	—	$	166

Liabilities:
Commodity derivatives	$	(49)	$	8	$	(41)	$	(183)	$	—	$	(183)

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 June 30, 2023 and December 31, 2022.


Balance Sheet Line Item	June 30, 2023		December 31, 2022		Balance Sheet Line Item	June 30, 2023		December 31, 2022
	(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	$	60	$	140	Unrealized losses on derivative instruments — current	$	(36)	$	(148)
Unrealized gains on derivative instruments — long-term	17		26		Unrealized losses on derivative instruments — long-term	(13)		(35)
Total	$	77	$	166	Total	$	(49)	$	(183)

For the six months ended June 30, 2023 and 2022, 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.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)				(millions)
Realized gains (losses)	$	13	$	(115)	$	60	$	(174)
Unrealized gains (losses)	7		101		47		(75)
Trading and marketing gains (losses), net	$	20	$	(14)	$	107	$	(249)

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.


	June 30, 2023
	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)
2023	—	(16,830,500)	(2,750,000)	1,280,000
2024	—	(15,966,800)	—	(235,000)
2025	—	(4,140,000)	—	2,985,000
2026	—	—	—	535,000


	June 30, 2022
	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 (Short) Long Position (MMBtu)
2022	(849,000)	(42,566,900)	(5,347,476)	(2,915,000)
2023	(1,526,000)	(26,655,000)	(4,281,200)	(16,572,500)
2024	(720,000)	(8,235,000)	(1,337,000)	(5,940,000)
2025	—	(7,300,000)	(1,441,000)	(980,000)
2026	—	—	(1,440,000)	535,000
2027	—	—	(600,000)	—

10. Partnership Equity and Distributions

Common Units — Following the completion of the Merger on June 15, 2023, all of the Common Units of the Partnership are owned by DCP Midstream, LLC, DCP Midstream GP, LP and Phillips 66 Project Development Inc., an indirect wholly owned subsidiary of Phillips 66. Former holders of Public Common Units ceased to have any rights as holders of Common Units at the Effective Time, other than the right to receive the Merger Consideration in accordance with the Merger Agreement. The Common Units were delisted from the NYSE and we filed to suspend our reporting obligations with respect to the Common Units under Sections 13 and 15(d) of the Securities Exchange Act of 1934, as amended.

Preferred Units — On June 15, 2023 we paid $161 million to redeem in full the outstanding Series B Preferred Units at a redemption price of $25 per unit using cash on hand and borrowings under our Securitization Facility. The difference between the redemption price of the Series B Preferred Units and the carrying value on the balance sheet resulted in an approximately $5 million reduction to net income allocable to limited partners. The carrying value represented the original issuance proceeds, net of underwriting fees and offering costs for the Series B Preferred Units. Following the redemption, the Series B Preferred Units

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

were delisted from the NYSE and we filed to suspend our reporting obligations with respect to the Series B Preferred Units under Sections 13 and 15(d) of the Securities Exchange Act of 1934, as amended.

Distributions — The following table presents our cash distributions paid in 2023:


Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
May 15, 2023	$	0.43	$	89
February 14, 2023	$	0.43	$	90






















Distributions to Series B Preferred unitholders
June 15, 2023	$	0.4922	$	3
March 15, 2023	$	0.4922	$	3













Distributions to Series C Preferred unitholders
April 17, 2023	$	0.4969	$	2
January 17, 2023	$	0.4969	$	2

11. Equity-Based Compensation

As of December 31, 2022, we had 327,190 Strategic Performance Units ("SPUs") and 532,432 Phantom Units outstanding. Pursuant to the terms of the Merger Agreement, the majority of these SPUs and Phantom Units were forfeited and as of June 30, 2023, there were an immaterial number of SPUs and Phantom Units outstanding.

12. Net Income or Loss per Limited Partner Unit

Prior to June 15, 2023, we had restricted phantom units outstanding, and we had the ability to elect to settle certain of the restricted phantom units in either cash or common units at our discretion. As of June 30, 2023, there were no outstanding equity classified restricted phantom units.

Basic and diluted net income per limited partner unit was calculated as follows for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions, except per unit amounts)

Net income allocable to limited partners	$	84	$	368	$	290	$	434
Weighted average limited partner units outstanding, basic	208,662,361		208,379,466		208,609,415		208,381,451
Dilutive effects of nonvested restricted phantom units	8,327		142,150		24,353		235,749
Weighted average limited partner units outstanding, diluted	208,670,688		208,521,616		208,633,768		208,617,200
Net income per limited partner unit, basic and diluted	$	0.40	$	1.77	$	1.39	$	2.08

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

13. 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 as well as general oil and gas production facilities and the real or perceived environmental or public health impacts of these activities, 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 agencies regarding the emission of greenhouse gases and other air emissions associated with our operations or the materials managed as part of our business, which could impose regulatory burdens and increase the cost of our operations; and (iv) regulatory bodies and communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.

The following pending proceedings involve governmental authorities as a party under federal, state, and local laws regulating the discharge of materials into the environment. We have elected to disclose matters where we reasonably believe such proceeding would result in monetary sanctions, exclusive of interest and costs, of $1 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 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. A revised air permit was issued in May 2019, but the parties had not yet entered into a final settlement agreement to complete the matter. 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,

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

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.

14. Restructuring Costs

We undertook restructuring actions, as well as other transformation and integration efforts, as part of our integration with Phillips 66. During the three and six months ended June 30, 2023, we incurred $16 million and $26 million, respectively, in impairment, severance and other employee related costs.


The following table presents a rollforward of the Company's restructuring liability as of June 30, 2023, which is primarily included in Other current liabilities in the condensed consolidated balance sheets:
	(millions)
Balance as of January 1, 2023	$	15
Severance and employee related charges	16

Cash payments	(30)
Balance as of June 30, 2023	$	1

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, 2022.

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

The following tables set forth our segment information:

Three Months Ended June 30, 2023


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	1,561	$	1,252	$	—	$	(972)	$	1,841
Adjusted gross margin (a)	$	58	$	371	$	—	$	—	$	429
Operating and maintenance expense	(8)		(216)		(5)		—		(229)
General and administrative expense	(1)		(4)		(63)		—		(68)
Depreciation and amortization expense	(4)		(84)		(3)		—		(91)




Loss on sale of assets, net	—		(3)		—		—		(3)
Restructuring costs	—		—		(16)		—		(16)
Earnings from unconsolidated affiliates	147		1		—		—		148
Interest expense	—		—		(75)		—		(75)

Net income (loss)	$	192	$	65	$	(162)	$	—	$	95
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	192	$	64	$	(162)	$	—	$	94
Non-cash derivative mark-to-market	$	17	$	(10)	$	—	$	—	$	7

Capital expenditures	$	1	$	81	$	—	$	—	$	82

Six Months Ended June 30, 2023:


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	3,953	$	3,018	$	—	$	(2,404)	$	4,567
Adjusted gross margin (a)	$	112	$	815	$	—	$	—	$	927
Operating and maintenance expense	(17)		(398)		(11)		—		(426)
General and administrative expense	(3)		(8)		(137)		—		(148)
Depreciation and amortization expense	(6)		(168)		(7)		—		(181)




Loss on sale of assets, net	—		(3)		—		—		(3)
Restructuring costs	—		—		(26)		—		(26)
Earnings from unconsolidated affiliates	301		7		—		—		308
Interest expense	—		—		(143)		—		(143)
Income tax expense	—		—		(1)		—		(1)
Net income (loss)	$	387	$	245	$	(325)	$	—	$	307
Net income attributable to noncontrolling interests	—		(2)		—		—		(2)
Net income (loss) attributable to partners	$	387	$	243	$	(325)	$	—	$	305
Non-cash derivative mark-to-market	$	12	$	35	$	—	$	—	$	47
Non-cash lower of cost or net realizable value adjustments	$	22	$	—	$	—	$	—	$	22
Capital expenditures	$	1	$	160	$	2	$	—	$	163

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022

Three Months Ended June 30, 2022


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	3,789	$	2,967	$	—	$	(2,487)	$	4,269
Adjusted gross margin (a)	$	40	$	585	$	—	$	—	$	625
Operating and maintenance expense	(9)		(175)		(5)		—		(189)
General and administrative expense	(2)		(5)		(58)		—		(65)
Depreciation and amortization expense	(3)		(82)		(5)		—		(90)
Asset impairments	—		(1)		—		—		(1)
Other income (expense), net	10		(2)		—		—		8




Earnings from unconsolidated affiliates	165		3		—		—		168
Interest expense	—		—		(70)		—		(70)
Income tax expense	—		—		(2)		—		(2)
Net income (loss)	$	201	$	323	$	(140)	$	—	$	384
Net income attributable to noncontrolling interests	—		(1)		—		—		(1)
Net income (loss) attributable to partners	$	201	$	322	$	(140)	$	—	$	383
Non-cash derivative mark-to-market	$	26	$	75	$	—	$	—	$	101

Capital expenditures	$	4	$	31	$	2	$	—	$	37
Investments in unconsolidated affiliates, net	$	—	$	—	$	—	$	—	$	—

Six Months Ended June 30, 2022:


	Logistics and Marketing		Gathering and Processing		Other		Eliminations		Total
	(millions)
Total operating revenue	$	6,952	$	5,073	$	—	$	(4,381)	$	7,644
Adjusted gross margin (a)	$	56	$	869	$	—	$	—	$	925
Operating and maintenance expense	(17)		(315)		(9)		—		(341)
General and administrative expense	(3)		(9)		(108)		—		(120)
Depreciation and amortization expense	(6)		(163)		(11)		—		(180)
Asset impairments	—		(1)		—		—		(1)
Other income (expense), net	10		(2)		—		—		8

Gain on sale of assets, net	—		7		—		—		7

Earnings from unconsolidated affiliates	302		9		—		—		311
Interest expense	—		—		(141)		—		(141)
Income tax expense	—		—		(3)		—		(3)
Net income (loss)	$	342	$	395	$	(272)	$	—	$	465
Net income attributable to noncontrolling interests	—		(2)		—		—		(2)
Net income (loss) attributable to partners	$	342	$	393	$	(272)	$	—	$	463

Non-cash derivative mark-to-market	$	(19)	$	(56)	$	—	$	—	$	(75)

Capital expenditures	$	6	$	51	$	3	$	—	$	60
Investments in unconsolidated affiliates, net	$	—	$	1	$	—	$	—	$	1

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2023 and 2022


	June 30,		December 31,
	2023		2022
	(millions)
Segment long-term assets:
Gathering and Processing	$	7,573	$	7,594
Logistics and Marketing	3,754		3,814
Other (b)	163		224
Total long-term assets	11,490		11,632
Current assets	1,002		1,702
Total assets	$	12,492	$	13,334

(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 similarly titled measures of other companies because other entities may not calculate adjusted gross margin in the same manner.

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

16. Supplemental Cash Flow Information


	Six Months Ended June 30,
	2023		2022
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	145	$	138
Cash paid for income taxes, net of income tax refunds	$	2	$	—
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	24	$	12
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	$	22	$	14

17. Subsequent Events

Distributions — On July 14, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution on our Common Units of $0.43 per Common Unit. The distribution will be paid on August 11, 2023 to unitholders of record on July 31, 2023.

Also on July 14, 2023, the board of directors of the General Partner declared a quarterly distribution on our Series C Preferred Units of $0.4969 per unit. The Series C distribution will be paid on October 16, 2023 to unitholders of record on October 2, 2023.

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, 2022.

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.

Completion of Merger with Phillips 66

On June 15, 2023, pursuant to the terms of the previously disclosed Agreement and Plan of Merger, dated as of January 5, 2023 (the “Merger Agreement”), by and among the Partnership, DCP Midstream GP, LP, the general partner of the Partnership (the “General Partner”), DCP Midstream GP, LLC, the general partner of the General Partner, Phillips 66, Phillips 66 Project Development Inc., an indirect wholly owned subsidiary of Phillips 66 (“PDI”), and Dynamo Merger Sub LLC, a wholly owned subsidiary of PDI (“Merger Sub”), Merger Sub merged with and into the Partnership, with the Partnership surviving as a Delaware limited partnership (the “Merger”).

We continue to integrate certain of our operations with Phillips 66’s midstream segment, including the integration of operational services that were previously provided by DCP Services, LLC. As part of these integration efforts, we incurred restructuring costs that primarily consisted of severance and employee related charges. Continuing employees transferred employment to a Phillips 66 subsidiary on April 1, 2023, and general and administrative services will be provided by Phillips 66 or one or more of its subsidiaries going forward. Phillips 66 is the managing member of our General Partner and, therefore, is responsible for conducting, directing, and managing our business and affairs.

General Trends and Outlook

We anticipate our business will continue to be affected by the key trends discussed herein. 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 portion of commodity price risk on an overall Partnership basis through our fee-based assets. 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 are volatile and are subject to global energy supply and demand fundamentals as well as geopolitical disruptions. Drilling activity levels vary by geographic area and we will continue to target our strategy in geographic areas where we expect producer drilling activity.

Our business is predominantly fee-based and we have a diversified portfolio to balance the upside of our earnings potential while reducing our commodity exposure. We expect future commodity prices will be influenced by global economic conditions and geopolitical disruptions, 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.

We expect to be a proactive participant in the transition to a lower carbon energy future through increased efficiency and modernization of existing operations, which we expect will reduce the greenhouse gas emissions from our base business. Going forward, our assets will be managed in a manner consistent with the emissions intensity reduction goals of Phillips 66.

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 negatively by, among other things, reduced drilling activity, depressed commodity prices, severe weather disruptions, operational outages and ethane rejection. Upstream producers response to changes in commodity prices and demand remain uncertain.

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, 9 have investment grade credit ratings.

The global economic outlook continues to be a 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 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 2023, our strategic objective is to generate Excess Free Cash Flows (a non-GAAP measure defined in “Reconciliation of Non-GAAP Measures - Excess Free Cash Flows”). We believe the key elements to generating Excess Free Cash Flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our estimated margins. 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 2023 plan includes sustaining capital expenditures of approximately $150 million and expansion capital expenditures of approximately $125 million.

Recent Events

Common and Preferred Distributions

On July 14, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution on our Common Units of $0.43 per Common Unit. The distribution will be paid on August 11, 2023 to unitholders of record on July 31, 2023.

Results of Operations

Consolidated Overview

The following table and discussion provides a summary of our consolidated results of operations for the three months ended June 30, 2023 and 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


		Three Months Ended June 30,				Six Months Ended June 30,				Variance Three Months 2023 vs. 2022	Variance Six Months 2023 vs. 2022
		2023		2022		2023		2022			Increase (Decrease)		Percent		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues (a):
Logistics and Marketing		$	1,561	$	3,789	$	3,953	$	6,952		$	(2,228)	(59	%)	$	(2,999)	(43	%)
Gathering and Processing		1,252		2,967		3,018		5,073			(1,715)		(58	%)	(2,055)		(41	%)
Inter-segment eliminations		(972)		(2,487)		(2,404)		(4,381)			(1,515)		(61	%)	(1,977)		(45	%)
Total operating revenues		1,841		4,269		4,567		7,644			(2,428)		(57	%)	(3,077)		(40	%)
Purchases and related costs
Logistics and Marketing		(1,503)		(3,749)		(3,841)		(6,896)			(2,246)		(60	%)	(3,055)		(44	%)
Gathering and Processing		(881)		(2,382)		(2,203)		(4,204)			(1,501)		(63	%)	(2,001)		(48	%)
Inter-segment eliminations		972		2,487		2,404		4,381			(1,515)		(61	%)	(1,977)		(45	%)
Total purchases		(1,412)		(3,644)		(3,640)		(6,719)			(2,232)		(61	%)	(3,079)		(46	%)
Operating and maintenance expense		(229)		(189)		(426)		(341)			40		21	%	85		25	%
Depreciation and amortization expense		(91)		(90)		(181)		(180)			1		1	%	1		1	%
General and administrative expense		(68)		(65)		(148)		(120)			3		5	%	28		23	%
Asset impairments		—		(1)		—		(1)			(1)		*		(1)		*
Other income, net		—		8		—		8			(8)		*		(8)		*
(Loss) gain on sale of assets, net		(3)		—		(3)		7			3		*		10		*
Restructuring costs		(16)		—		(26)		—			16		*		26		*

Earnings from unconsolidated affiliates (b)		148		168		308		311			(20)		(12	%)	(3)		(1	%)
Interest expense		(75)		(70)		(143)		(141)			5		7	%	2		1	%
Income tax expense		—		(2)		(1)		(3)			(2)		*		(2)		(67	%)
Net income attributable to noncontrolling interests		(1)		(1)		(2)		(2)			—		—	%	—		—	%
Net income attributable to partners		$	94	$	383	$	305	$	463		$	(289)	(75	%)	$	(158)	(34	%)
Other data:
Adjusted gross margin (c):
Logistics and Marketing		$	58	$	40	$	112	$	56		$	18	45	%	$	56	*
Gathering and Processing		371		585		815		869			(214)		(37	%)	(54)		(6	%)
Total adjusted gross margin		$	429	$	625	$	927	$	925		$	(196)	(31	%)	$	2	—	%

Non-cash commodity derivative mark-to-market		$	7	$	101	$	47	$	(75)		$	(94)	(93	%)	$	122	*
NGL pipelines throughput (MBbls/d) (d)		702		720		713		701			(18)		(3	%)	12		2	%
Gas pipelines throughput (TBtu/d) (d)		1.07		1.09		1.08		1.09			(0.02)		(2	%)	(0.01)		(1	%)
Natural gas wellhead (MMcf/d) (d)		4,481		4,383		4,477		4,246			98		2	%	231		5	%
NGL gross production (MBbls/d) (d)		446		427		433		414			19		4	%	19		5	%

* 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 June 30, 2023 vs. Three Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $2,428 million in 2023 compared to 2022, primarily as a result of the following:

•$2,228 million decrease for our Logistics and Marketing segment, primarily due to lower commodity prices, partially offset by higher gas and NGL volumes, and favorable commodity derivative activity; and

•$1,715 million decrease for our Gathering and Processing segment, primarily due to lower commodity prices and a decrease in transportation, processing and other, partially offset by higher volumes across all regions and favorable commodity derivative activity.

These decreases were partially offset by:

•$1,515 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity prices.

Total Purchases — Total purchases decreased $2,232 million in 2023 compared to 2022, primarily as a result of the following:

•$2,246 million decrease for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$1,501 million decrease for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These decreases was partially offset by:

•$1,515 million change in inter-segment eliminations, for the reasons discussed above.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2023 compared to 2022 largely due to a legal settlement, higher base costs primarily in the Permian region and higher pipeline integrity spend.

Other Income — Other income in 2022 was primarily a result of contractual settlements.

Restructuring Costs — Restructuring costs in 2023 was primarily a result of an impairment, severance for termination benefits and other costs as a result of our ongoing integration with Phillips 66.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2023 compared to 2022 primarily as a result of a contract amendment with a third party customer that modified performance obligations and conditions, resulting in higher non-recurring earnings on the Sand Hills pipeline in 2022.

Net Income Attributable to Partners — Net income attributable to partners decreased in 2023 compared to 2022 for all of the reasons discussed above.

Adjusted Gross Margin — Adjusted gross margin decreased $196 million in 2023 compared to 2022, primarily as a result of the following:

•$214 million decrease for our Gathering and Processing segment, primarily as a result of lower commodity prices and lower margins in the South region, partially offset by favorable derivative activity attributable to our corporate equity hedge program and higher volumes in the Permian region; partially offset by

•$18 million increase for our Logistics and Marketing segment, primarily as a result of favorable commodity derivative activity on gas pipelines, a contract settlement in 2022, and improved NGL pipeline margins, partially offset by unfavorable NGL marketing activity and lower gas storage margins.

NGL Pipelines Throughput — NGL pipelines throughput decreased in 2023 compared to 2022 due to decreased volumes on the Sand Hills and Front Range pipelines, partially offset by increased throughput on Southern Hills pipeline.

Natural Gas Wellhead — Natural gas wellhead increased in 2023 compared to 2022 due to increased volumes in the Permian region and DJ Basin, partially offset by lower volumes in the Midcontinent region.

NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian, South, and Midcontinent regions.

Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $3,077 million in 2023 compared to 2022, primarily as a result of the following:

•$2,999 million decrease for our Logistics and Marketing segment, primarily due to lower commodity prices, partially offset by higher gas and NGL volumes, and favorable commodity derivative activity; and

•$2,055 million decrease for our Gathering and Processing segment, primarily due to lower commodity prices and a decrease in transportation, processing and other, partially offset by higher volumes across all regions and favorable commodity derivative activity.

These decreases were partially offset by:

•$1,977 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity prices.

Total Purchases — Total purchases decreased $3,079 million in 2023 compared to 2022, primarily as a result of the following:

•$3,055 million decrease for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and

•$2,001 million decrease for our Gathering and Processing segment for the commodity price and volume changes discussed above.

These decreases were partially offset by:

•$1,977 million change in inter-segment eliminations, for the reasons discussed above.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2023 compared to 2022 largely due to higher base costs primarily in the Permian region, a legal settlement, and higher pipeline integrity spend.

General and Administrative Expense — General and administrative expense increased in 2023 compared to 2022, primarily due to higher integration costs and employee costs.

Other Income, Net — Other income in 2022 was primarily a result of contractual settlements.

(Loss) gain on sale of assets, net — The net loss on sale of assets in 2023 represents the sale of certain non-core assets in the Midcontinent region. The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region.

Restructuring Costs — Restructuring costs in 2023 was primarily a result of severance for termination benefits, an impairment and other costs as a result of our ongoing integration with Phillips 66.

Net Income Attributable to Partners — Net income attributable to partners decreased in 2023 compared to 2022 for all of the reasons discussed above.

Adjusted Gross Margin — Adjusted gross margin increased $2 million in 2023 compared to 2022, primarily as a result of the following:

•$56 million increase for our Logistics and Marketing segment, primarily as a result of favorable commodity derivative activity on gas pipelines, a contract settlement, and higher NGL pipeline margins, partially offset by lower gas storage and pipeline margins, unfavorable NGL marketing activity and lower NGL storage margins; offset by

•$54 million decrease for our Gathering and Processing segment, primarily as a result of lower commodity prices and lower margins in the South, DJ Basin and Midcontinent regions, partially offset by favorable derivative activity attributable to our corporate equity hedge program, higher volumes in the Permian, South and DJ Basin, and improved performance in the Permian region.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2023 compared to 2022 due to increased volumes on the Sand Hills pipeline.

Natural Gas Wellhead — Natural gas wellhead increased in 2023 compared to 2022 due to increased volumes in the Permian region, South region, and DJ Basin, partially offset by lower volumes in the Midcontinent region.

NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian region, DJ Basin, and South region.

Supplemental Information on Unconsolidated Affiliates

The following tables present financial information related to unconsolidated affiliates during the three and six months ended June 30, 2023 and 2022, respectively:

Earnings from investments in unconsolidated affiliates were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
DCP Sand Hills Pipeline, LLC	$	78	$	104	$	165	$	175
DCP Southern Hills Pipeline, LLC	27		21		52		45
Gulf Coast Express LLC	18		16		35		32
Front Range Pipeline LLC	11		11		22		21
Texas Express Pipeline LLC	5		5		10		10
Mont Belvieu 1 Fractionator	4		3		8		7
Discovery Producer Services LLC	1		3		7		9
Cheyenne Connector, LLC	3		3		6		7
Mont Belvieu Enterprise Fractionator	1		2		2		4

Other	—		—		1		1
Total earnings from unconsolidated affiliates	$	148	$	168	$	308	$	311

Distributions received from unconsolidated affiliates were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
DCP Sand Hills Pipeline, LLC	$	100	$	117	$	182	$	200
DCP Southern Hills Pipeline, LLC	32		28		60		56
Gulf Coast Express LLC	20		20		41		40
Front Range Pipeline LLC	14		12		27		24
Texas Express Pipeline LLC	8		6		14		12
Mont Belvieu 1 Fractionator	3		2		6		6
Discovery Producer Services LLC	7		7		18		15
Cheyenne Connector, LLC	5		5		9		10
Mont Belvieu Enterprise Fractionator	3		3		2		4

Other	—		1		1		2
Total distributions from unconsolidated affiliates	$	192	$	201	$	360	$	369

Results of Operations — Logistics and Marketing Segment


Operating Data
					Three Months Ended June 30, 2023			Six Months Ended June 30, 2023
System	Approximate System Length (Miles)	Fractionators	Approximate Throughput Capacity (MBbls/d) (a)	Approximate Gas Throughput Capacity (TBtus/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	—		295	—		304	—
Southern Hills pipeline	950	—	128	—		126	—		121	—
Front Range pipeline	450	—	87	—		73	—		75	—
Texas Express pipeline	600	—	37	—		22	—		22	—
Other NGL pipelines (a)	1,050	—	310	—		186	—		191	—
Gulf Coast Express pipeline	500	—	—	0.50		—	0.51		—	0.50
Guadalupe pipeline	600	—	—	0.25		—	0.26		—	0.27
Cheyenne Connector	70	—	—	0.30		—	0.30		—	0.31
Mont Belvieu fractionators	—	2	—	—		—	—		—	—
Pipelines total	5,620	2	895	1.05		702	1.07		713	1.08

(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 June 30,				Six Months Ended June 30,				Variance Three Months 2023 vs. 2022			Variance Six Months 2023 vs. 2022
	2023		2022		2023		2022			Increase (Decrease)		Percent		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	1,524	$	3,769	$	3,854	$	6,954		$	(2,245)	(60	%)	$	(3,100)	(45	%)
Transportation, processing and other	18		18		37		37			—		—	%	—		—	%
Trading and marketing gains (losses), net	19		2		62		(39)			17		*		101		*
Total operating revenues	1,561		3,789		3,953		6,952			(2,228)		(59	%)	(2,999)		(43	%)
Purchases and related costs	(1,503)		(3,749)		(3,841)		(6,896)			(2,246)		(60	%)	(3,055)		(44	%)
Operating and maintenance expense	(8)		(9)		(17)		(17)			(1)		(11	%)	—		—	%
Depreciation and amortization expense	(4)		(3)		(6)		(6)			1		33	%	—		—	%
General and administrative expense	(1)		(2)		(3)		(3)			(1)		(50	%)	—		—	%

Other income, net	—		10		—		10			(10)		*		(10)		*
Earnings from unconsolidated affiliates (a)	147		165		301		302			(18)		(11	%)	(1)		—	%

Segment net income attributable to partners	$	192	$	201	$	387	$	342		$	(9)	(4	%)	$	45	13	%
Other data:
Segment adjusted gross margin (b)	$	58	$	40	$	112	$	56		$	18	45	%	$	56	*
Non-cash commodity derivative mark-to-market	$	17	$	26	$	12	$	(19)		$	(9)	(35	%)	$	31	*
NGL pipelines throughput (MBbls/d) (c)	702		720		713		701			(18)		(3	%)	12		2	%
Gas pipelines throughput (TBtu/d) (c)	1.07		1.09		1.08		1.09			(0.02)		(2	%)	(0.01)		(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.

(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 June 30, 2023 vs. Three Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $2,228 million in 2023 compared to 2022, primarily as a result of the following:

•$2,278 million decrease as a result of lower commodity prices before the impact of derivative activity.

This decrease was partially offset by:

•$33 million increase attributable to higher gas and NGL volumes; and

•$17 million increase as a result of commodity derivative activity attributable to a increase in realized cash settlement gains of $26 million, partially offset by an decrease in unrealized commodity derivative gains of $9 million due to movements in forward prices of commodities.

Purchases and Related Costs — Purchases and related costs decreased $2,246 million in 2023 compared to 2022, for the reasons discussed above.

Other Income — Other income in 2022 was primarily a result of contractual settlements.

Segment Adjusted Gross Margin — Segment adjusted gross margin increased $18 million in 2023 compared to 2022, primarily as a result of the following:

•$17 million increase as a result of commodity derivative activity discussed above;

•$16 million contract settlement in 2022; and

•$3 million increase as a result of NGL pipeline margins.

These increases were partially offset by:

•$11 million decrease as a result of unfavorable NGL marketing activity; and

•$7 million decrease as a result of lower gas storage margins.

Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $2,999 million in 2023 compared to 2022, primarily as a result of the following:

•$3,318 million decrease as a result of lower commodity prices before the impact of derivative activity.

This decrease was partially offset by:

•$218 million increase attributable to higher gas and NGL volumes; and

•$101 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $70 million and an increase in unrealized commodity derivative gains of $31 million due to movements in forward prices of commodities.

Purchases and Related Costs — Purchases and related costs decreased $3,055 million in 2023 compared to 2022, for the reasons discussed above.

Other Income, Net — Other income in 2022 was primarily a result of contractual settlements.

Segment Adjusted Gross Margin — Segment adjusted gross margin increased $56 million in 2023 compared to 2022, primarily as a result of the following:

•$101 million increase as a result of commodity derivative activity as discussed above;

•$16 million contract settlement in 2022; and

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

These increases were partially offset by:

•$39 million decrease as a result of lower gas storage and pipeline margins;

•$23 million decrease as a result of unfavorable NGL marketing activity; and

•$4 million decrease as a result of lower NGL storage margins.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2023 compared to 2022 due to increased volumes on the Sand Hills pipeline.

Results of Operations — Gathering and Processing Segment


Operating Data
				Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
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	1,589	157	1,582	157
Midcontinent	6	23,000	1,110	812	77	808	70
Permian	10	15,000	1,220	1,104	134	1,097	134
South	7	6,500	1,630	976	78	990	72
Total	36	48,000	5,540	4,481	446	4,477	433

(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 June 30,				Six Months Ended June 30,				Variance Three Months 2023 vs. 2022			Variance Six Months 2023 vs. 2022
		2023		2022		2023		2022			Increase (Decrease)		Percent		Increase (Decrease)		Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	1,121	$	2,817	$	2,699	$	4,981		$	(1,696)	(60	%)	$	(2,282)	(46	%)
Transportation, processing and other		130		166		274		302			(36)		(22	%)	(28)		(9	%)
Trading and marketing gains (losses), net		1		(16)		45		(210)			17		*		255		*
Total operating revenues		1,252		2,967		3,018		5,073			(1,715)		(58	%)	(2,055)		(41	%)
Purchases and related costs		(881)		(2,382)		(2,203)		(4,204)			(1,501)		(63	%)	(2,001)		(48	%)
Operating and maintenance expense		(216)		(175)		(398)		(315)			41		23	%	83		26	%
Depreciation and amortization expense		(84)		(82)		(168)		(163)			2		2	%	5		3	%
General and administrative expense		(4)		(5)		(8)		(9)			(1)		(20)	%	(1)		(11	%)
Asset impairments		—		(1)		—		(1)			(1)		*		(1)		*
Other expense, net		—		(2)		—		(2)			(2)		*		(2)		*
(Loss) gain on sale of assets, net		(3)		—		(3)		7			(3)		*		(10)		*
Earnings from unconsolidated affiliates (a)		1		3		7		9			(2)		*		(2)		(22	%)
Segment net income		65		323		245		395			(258)		(80	%)	(150)		(38	%)
Segment net income attributable to noncontrolling interests		(1)		(1)		(2)		(2)			—		—	%	—		—	%
Segment net income attributable to partners		$	64	$	322	$	243	$	393		$	(258)	(80	%)	$	(150)	(38	%)
Other data:
Segment adjusted gross margin (b)		$	371	$	585	$	815	$	869		$	(214)	(37	%)	$	(54)	(6	%)
Non-cash commodity derivative mark-to-market		$	(10)	$	75	$	35	$	(56)		$	(85)	*		$	91	*
Natural gas wellhead (MMcf/d) (c)		4,481		4,383		4,477		4,246			98		2	%	231		5	%
NGL gross production (MBbls/d) (c)		446		427		433		414			19		4	%	19		5	%

* 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) 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 June 30, 2023 vs. Three Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $1,715 million in 2023 compared to 2022, primarily as a result of the following:

• $1,882 million decrease attributable to lower commodity prices, before the impact of derivative activity; and

•$36 million decrease in transportation, processing and other.

These decreases was partially offset by:

• $186 million increase as a result of higher volumes in all regions; and

•$17 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $102 million, partially offset by an $85 million increase in unrealized commodity derivative losses due to movements in forward prices of commodities in 2023.

Purchases and Related Costs — Purchases and related costs decreased $1,501 million in 2023 compared to 2022, primarily as a result of the commodity price and volume changes discussed above.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $214 million in 2023 compared to 2022, primarily as a result of the following:

•$227 million decrease as a result of lower commodity prices; and

•$4 million decrease due to lower margins in the South region, partially offset by higher volumes in the Permian region.

These decreases were partially offset by:

•$17 million increase as a result of favorable commodity derivative activity discussed above.

NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian, South, and Midcontinent regions.

Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022

Total Operating Revenues — Total operating revenues decreased $2,055 million in 2023 compared to 2022, primarily as a result of the following:

•$2,621 million decrease attributable to lower commodity prices, before the impact of derivative activity; and

•$28 million decrease in transportation, processing and other.

These decreases were partially offset by:

•$339 million increase as a result of higher volumes in all regions; and

•$255 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $164 million due to movements in forward prices of commodities in 2023 and a $91 million increase in unrealized commodity derivative gains.

Purchases and Related Costs — Purchases and related costs decreased $2,001 million in 2023 compared to 2022, primarily as a result of the commodity price and volume changes discussed above.

(Loss) gain on Sale of Assets, net — The net loss on sale of assets in 2023 represents the sale of certain non-core assets in the Midcontinent region. The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region.

Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $54 million in 2023 compared to 2022, primarily as a result of the following:

•$310 million decrease as a result of lower commodity prices.

These decreases were partially offset by:

•$255 million increase as a result of favorable commodity derivative activity as discussed above; and

•$1 million increase due to higher volumes in the Permian region, South region and DJ Basin, and improved performance in the Permian region, partially offset by lower margins in the South region, DJ Basin, and Midcontinent region.

NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian region, DJ Basin, and South region.

Liquidity and Capital Resources

We expect our sources of liquidity to include:

•cash generated from operations;

•cash distributions from our unconsolidated affiliates;

•borrowings under our Credit Agreement, Intercompany Credit Agreement, and Securitization Facility;

•proceeds from asset rationalizations;

•debt offerings; and

•borrowings under term loans, or other credit facilities.

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 or retire our debt or Preferred Units;

•capital expenditures; and

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

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.

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 or debt instruments 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, Intercompany Credit Agreement, and other debt instruments.

Junior Notes Redemption — On May 19, 2023, we redeemed, at par, prior to maturity all $550 million of aggregate principal amount outstanding of our 5.850% Junior Notes due May 2043, using borrowings under our Credit Facility and Securitization Facility.

Series B Preferred Units Redemption — On June 15, 2023 we paid $161 million to redeem in full the outstanding Series B Preferred Units at a redemption price of $25 per unit using cash on hand and borrowings under our Securitization Facility. The difference between the redemption price of the Series B Preferred Units and the carrying value on the balance sheet resulted in an approximately $5 million reduction to net income allocable to limited partners. The carrying value represented the original issuance proceeds, net of underwriting fees and offering costs for the Series B Preferred Units.

Intercompany Credit Agreement — On June 15, 2023, we and our wholly owned subsidiary, DCP Midstream Operating, LP, entered into a new five-year revolving Intercompany Credit Agreement with Phillips 66, as lender. The Intercompany Credit Agreement provides up to $1 billion of borrowing capacity, with an option to increase the commitment by an aggregate principal amount of up to $500 million, subject to lender approval. At our election, the Intercompany Credit Agreement bears interest at either the adjusted term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. A ratings-based pricing grid determines our cost of borrowing under the Intercompany Credit Agreement. Indebtedness under the Intercompany Credit Agreement bears interest at either: (1) SOFR, plus an applicable margin of 1.075% based on our current credit rating, plus an adjustment of 0.10%; or (2) (a) the base rate, which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the SOFR Market Index rate plus 1.00%, plus (b) an applicable margin of 0.075% based on our current credit rating. Based on our current credit rating, the Intercompany Credit Agreement incurs an annual facility fee of 0.175%.

Credit Agreement — We are party to a Credit Agreement that provides up to $1.4 billion of borrowing capacity and bears interest at either the term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. The Credit Agreement matures on March 18, 2027.

As of June 30, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 million letters of credit, under the Credit Agreement, of which at least $548 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. As of July 28, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 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 June 30, 2023, we had $280 million of outstanding borrowings under the Securitization Facility at the SOFR rate plus a margin.

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 $73 million and $80 million as of June 30, 2023 and December 31, 2022, respectively;

•Balances related to debt of $4.728 billion and $4.823 billion as of June 30, 2023 and December 31, 2022, respectively; and

•Interest expense, net of $69 million and $69 million for the three months ended June 30, 2023 and 2022, respectively, and $135 million and $138 million for the six months ended June 30, 2023 and 2022, respectively.

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

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

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

We had working capital deficits of $142 million and $802 million as of June 30, 2023 and December 31, 2022, respectively, driven by current maturities of long term debt of $7 million and $506 million, respectively. We had net derivative working capital surplus of $24 million and deficit of $8 million as of June 30, 2023 and December 31, 2022, respectively.

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


	Six Months Ended June 30,
	2023		2022
	(millions)
Net cash provided by operating activities	$	369	$	574
Net cash used in investing activities	$	(151)	$	(61)
Net cash used in financing activities	$	(218)	$	(506)

Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022

Operating Activities — Net cash provided by operating activities decreased $205 million in 2023 compared to the same period in 2022. The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges and changes in working capital as presented in the condensed consolidated statements of cash flows. For additional information regarding fluctuations in our earnings and distributions from unconsolidated affiliates, please read “Supplemental Information on Unconsolidated Affiliates” under “Results of Operations”.

Investing Activities — Net cash used in investing activities increased $90 million in 2023 compared to the same period in 2022, primarily as a result of an increase in capital expenditures, partially offset by a return of capital from an investment and proceeds from the sale of assets.

Financing Activities — Net cash used in financing activities decreased $288 million in 2023 compared to the same period in 2022, primarily as a result of lower net payments of debt, partially offset by the redemption of the Series B Preferred Units.

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, asset retirement obligations, and other long-term liabilities. See Note 8 "Debt" in the Notes to the Condensed Consolidated Financial Statements in Item 1. "Financial Statements" for amounts outstanding on June 30, 2023, related to debt. Lease and asset retirement obligations are not materially different from what was disclosed in Notes 14 and 15, respectively, to the Consolidated Financial Statements included in Item 8 "Financial Statements" in Part II of form 10-K for the year ended December 31, 2022.

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. In the ordinary course of our business, we purchase physical commodities and enter into arrangements related to other items, including long-term fractionation and transportation agreements, in future periods. We establish a margin for these purchases by entering into physical and financial sale and exchange transactions to maintain a balanced position between purchases and sales and future delivery obligations. We expect to fund the obligations with the corresponding sales to entities that we deem creditworthy or that have provided credit support we consider adequate. 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 incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2023 plan includes sustaining capital expenditures of $150 million and expansion capital expenditures of $125 million.

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

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 $179 million and $163 million during the six months ended June 30, 2023 and 2022, respectively.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders. See Note 10 “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 the board of directors of the General Partner, 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. 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 similarly titled measures of other companies 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. 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 similarly titled measures of other companies 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Reconciliation of Non-GAAP Measures	(millions)

Reconciliation of gross margin to adjusted gross margin:

Operating revenues	$	1,841	$	4,269	$	4,567	$	7,644
Cost of revenues
Purchases and related costs	1,112		3,269		2,964		5,988
Purchases and related costs from affiliates	12		100		109		199
Transportation and related costs from affiliates	288		275		567		532
Depreciation and amortization expense	91		90		181		180
Gross margin	338		535		746		745
Depreciation and amortization expense	91		90		181		180
Adjusted gross margin	$	429	$	625	$	927	$	925



Reconciliation of segment gross margin to segment adjusted gross margin:

Logistics and Marketing segment:
Operating revenues	$	1,561	$	3,789	$	3,953	$	6,952
Cost of revenues
Purchases and related costs	1,503		3,749		3,841		6,896
Depreciation and amortization expense	4		3		6		6
Segment gross margin	54		37		106		50
Depreciation and amortization expense	4		3		6		6
Segment adjusted gross margin	$	58	$	40	$	112	$	56



Gathering and Processing segment:
Operating revenues	$	1,252	$	2,967	$	3,018	$	5,073
Cost of revenues
Purchases and related costs	881		2,382		2,203		4,204
Depreciation and amortization expense	84		82		168		163
Segment gross margin	287		503		647		706
Depreciation and amortization expense	84		82		168		163
Segment adjusted gross margin	$	371	$	585	$	815	$	869


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:

Logistics and Marketing segment:
Segment net income attributable to partners (a)	$	192	$	201	$	387	$	342
Non-cash commodity derivative mark-to-market	(17)		(26)		(12)		19
Depreciation and amortization expense, net of noncontrolling interest	4		3		6		6
Distributions from unconsolidated affiliates, net of earnings	38		29		41		52


Other (income) expense	—		(2)		—		(2)
Adjusted segment EBITDA	$	217	$	205	$	422	$	417

Gathering and Processing segment:
Segment net income attributable to partners	$	64	$	322	$	243	$	393
Non-cash commodity derivative mark-to-market	10		(75)		(35)		56
Depreciation and amortization expense, net of noncontrolling interest	84		81		168		162
Distributions from unconsolidated affiliates, net of earnings	6		4		11		6
Asset impairments	—		1		—		1

Loss (gain) on sale of assets	3		—		3		(7)

Other expenses	—		2		—		2
Adjusted segment EBITDA	$	167	$	335	$	390	$	613

(a) We recognized zero and $22 million of lower of cost or net realizable value adjustment for the three and six months ended June 30, 2023, respectively. We recognized no lower of cost or net realizable value adjustment for the three and six months ended June 30, 2022.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in "Critical Accounting 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, 2022 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, 2022. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and six months ended June 30, 2023 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2022. 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, 2022.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Our sensitivities for 2023 as shown in the table below are estimated based on our average estimated 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	$	10
Natural gas prices	$	0.10	MMBtu	$	6
Crude oil prices	$	1.00	Barrel	$	5

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.

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.

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-net realizable value 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 June 30, 2023:

Inventory

Period ended

Commodity

Notional Volume - Long
Positions

Fair Value
(millions)

Weighted
Average Price

June 30, 2023

Natural Gas

11,550,402

MMBtu

$1.76/MMBtu

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long
Positions

Fair Value
(millions)

Price Range

July 2023 — January 2025

Natural Gas

(26,215,000)

MMBtu

$2.18-$5.98/MMBtu

July 2023 — December 2024

Natural Gas

15,192,500

MMBtu

(2)

$2.16-$5.20/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 June 30, 2023:

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long Positions

Fair Value (millions)

Price Range (a)

July 2023 — December 2026

Natural Gas

(46,517,500)

MMBtu

$0.02-$0.14/MMBtu

July 2023 — December 2026

Natural Gas

44,555,000

MMBtu

(10)

$0.09-$0.71/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 interim principal executive and interim 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 June 30, 2023, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of June 30, 2023, 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 June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

The information provided in “Commitments and Contingent Liabilities” included in (a) Note 22 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, 2022 and (b) Note 13 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, 2022. There are no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2022.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number

Description

2.1

Agreement and Plan of Merger, dated January 5, 2023, by and among Phillips 66, Phillips 66 Project Development Inc., Dynamo Merger Sub LLC, DCP Midstream, LP, DCP Midstream GP, LP and DCP Midstream GP, LLC (attached as Exhibit 2.1 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2023).

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 Partners, 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

Limited Waiver to Third Amended and Restated Credit Agreement dated May 22, 2023, by and among DCP Midstream Operating, LP, Mizuho Bank, Ltd., as administrative agent, and the lenders party thereto.

10.2

Letter of Separation between Phillips 66 and George R. Green

10.3

Credit Agreement, dated as of June 15, 2023, by and among DCP Midstream, LP, as guarantor, DCP Midstream Operating, LP, as borrower, and Phillips 66 Company, as lender (attached as Exhibit 10.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June 15, 2023).

List of Guaranteed Securities

31.1

Certification of Interim Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Interim Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Interim 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 Interim 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 six months ended June 30, 2023, formatted in XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statements of Changes in Equity, and (vi) the Notes to the Condensed Consolidated Financial Statements.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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

+ Denotes management contract or compensatory plan or arrangement.

# Pursuant to Item 601(b)(10)(iv) of Regulation S-K, the Partnership agrees to furnish supplementally an unredacted copy of

this exhibit to the Securities and Exchange Commission upon request.

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: August 3, 2023

By:

/s/ Donald A. Baldridge

Name:

Donald A. Baldridge

Title:

Interim Chief Executive Officer

(Principal Executive Officer)

Date: August 3, 2023

By:

/s/ Scott R. Delmoro

Name:

Scott R. Delmoro

Title:

Interim Chief Financial Officer

(Principal Financial Officer)