DCP Midstream, LP - Quarter Report: 2019 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2019



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

For the transition period from to

Commission File Number: 001-32678

DCP MIDSTREAM, LP

(Exact name of registrant as specified in its charter)



Delaware		03-0567133
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

370 17th Street, Suite 2500 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 595-3331

(Registrant’s telephone number, including area code)

None

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ý No ¨

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



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

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

of the Exchange Act. ¨

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

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



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

As of May 1, 2019, there were 143,317,328 common units representing limited partner interests outstanding.

DCP MIDSTREAM, LP

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2019

TABLE OF CONTENTS




Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2019 and 2018	2
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2019 and 2018	4
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2019	5
	Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2018	6
	Notes to the Condensed Consolidated Financial Statements	7
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
3.	Quantitative and Qualitative Disclosures about Market Risk	55
4.	Controls and Procedures	58
	PART II. OTHER INFORMATION
1.	Legal Proceedings	59
1A.	Risk Factors	59
6.	Exhibits	60
	Signatures	61

GLOSSARY OF TERMS

The following is a list of certain industry terms used throughout this report:




Bbl		barrel
Bbls/d		barrels per day
Bcf		billion cubic feet
Bcf/d		billion cubic feet per day
Btu		British thermal unit, a measurement of energy
Fractionation		the process by which natural gas liquids are separated into individual components
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
Throughput		the volume of product transported or passing through a pipeline or other facility

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in Item 1A. "Risk Factors" in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, and in our Annual Report on Form 10-K for the year ended December 31, 2018, including the following risks and uncertainties:

•

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 market and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, including additional local control over such activities, and their impact on producers and customers served by our systems;


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


•	general economic, market and business conditions;

•

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


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


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


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


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


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


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


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


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


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


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

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

iii

PART I

Item 1. Financial Statements

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2019			December 31, 2018
ASSETS	(millions)
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $3 and $3 million, respectively	732			860
Affiliates	176			166
Other	6			7
Inventories	52			79
Unrealized gains on derivative instruments	35			108
Collateral cash deposits	64			34
Other	16			16
Total current assets	1,082			1,271
Property, plant and equipment, net	9,110			9,135
Goodwill	194			231
Intangible assets, net	77			97
Investments in unconsolidated affiliates	3,460			3,340
Unrealized gains on derivative instruments	2			8
Operating lease assets	78			—
Other long-term assets	184			184
Total assets	$	14,187		$	14,266
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	786		$	807
Affiliates	116			96
Other	30			23
Current debt	1,125			525
Unrealized losses on derivative instruments	61			91
Accrued interest	72			71
Accrued taxes	65			64
Accrued wages and benefits	25			64
Capital spending accrual	28			63
Other	96			100
Total current liabilities	2,404			1,904
Long-term debt	4,236			4,782
Unrealized losses on derivative instruments	5			8
Deferred income taxes	32			32
Operating lease liabilities	66			—
Other long-term liabilities	231			243
Total liabilities	6,974			6,969
Commitments and contingent liabilities (see note 18)
Equity:
Series A preferred limited partners (500,000 preferred units authorized, issued and outstanding, respectively)	498			489
Series B preferred limited partners (6,450,000 preferred units authorized, issued and outstanding, respectively)	156			156
Series C preferred limited partners (4,400,000 preferred units authorized, issued and outstanding, respectively)	106			106
General partner	105			107
Limited partners (143,317,328 common units authorized, issued and outstanding, respectively)	6,327			6,418
Accumulated other comprehensive loss	(8		)	(8		)
Total partners’ equity	7,184			7,268
Noncontrolling interests	29			29
Total equity	7,213			7,297
Total liabilities and equity	$	14,187		$	14,266

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



		Three Months Ended March 31,
		2019			2018
	(millions, except per unit amounts)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	1,771		$	1,744
Sales of natural gas, NGLs and condensate to affiliates		340			325
Transportation, processing and other		115			111
Trading and marketing losses, net		(27		)	(41		)
Total operating revenues		2,199			2,139
Operating costs and expenses:
Purchases and related costs		1,533			1,604
Purchases and related costs from affiliates		271			165
Operating and maintenance expense		178			162
Depreciation and amortization expense		103			94
General and administrative expense		67			59
Other expense, net		5			2
Loss on sale of assets, net		9			—
Total operating costs and expenses		2,166			2,086
Operating income		33			53
Earnings from unconsolidated affiliates		113			78
Interest expense, net		(69		)	(67		)
Income before income taxes		77			64
Income tax expense		(1		)	(1		)
Net income		76			63
Net income attributable to noncontrolling interests		(1		)	(1		)
Net income attributable to partners		75			62
Series A preferred limited partners' interest in net income		(9		)	(9		)
Series B preferred limited partners' interest in net income		(3		)	—
Series C preferred limited partners' interest in net income		(2		)	—
General partner’s interest in net income		(41		)	(41		)
Net income allocable to limited partners		$	20		$	12
Net income per limited partner unit — basic and diluted		$	0.14		$	0.08
Weighted-average limited partner units outstanding — basic and diluted		143.3			143.3

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



		Three Months Ended March 31,
		2019			2018
	(millions)
Net income		$	76		$	63
Other comprehensive income:
Total other comprehensive income		—			—
Total comprehensive income		76			63
Total comprehensive income attributable to noncontrolling interests		(1		)	(1		)
Total comprehensive income attributable to partners		$	75		$	62

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2019			2018
	(millions)
OPERATING ACTIVITIES:
Net income	$	76		$	63
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	103			94
Earnings from unconsolidated affiliates	(113		)	(78		)
Distributions from unconsolidated affiliates	124			91
Net unrealized losses on derivative instruments	54			29
Loss on sale of assets, net	9			—
Other, net	6			6
Change in operating assets and liabilities, which provided (used) cash:
Accounts receivable	118			161
Inventories	14			17
Accounts payable	29			(151		)
Other assets and liabilities	(103		)	(110		)
Net cash provided by operating activities	317			122
INVESTING ACTIVITIES:
Capital expenditures	(182		)	(124		)
Investments in unconsolidated affiliates	(131		)	(60		)
Proceeds from sale of assets	103			3
Net cash used in investing activities	(210		)	(181		)
FINANCING ACTIVITIES:
Proceeds from debt	1,402			635
Payments of debt	(1,348		)	(535		)
Distributions to preferred limited partners	(5		)	—
Distributions to limited partners and general partner	(154		)	(194		)
Distributions to noncontrolling interests	(1		)	(1		)
Other	(1		)	—
Net cash used in financing activities	(107		)	(95		)
Net change in cash and cash equivalents	—			(154		)
Cash and cash equivalents, beginning of period	1			156
Cash and cash equivalents, end of period	$	1		$	2

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



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

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Partners’ Equity
		Series A Preferred Limited Partners		Limited Partners			General Partner			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
	(millions)
Balance, January 1, 2018		$	491	$	6,772		$	154		$	(9	)	$	30		$	7,438
Cumulative-effect adjustment		—		6			—			—			—			6
Net income		9		12			41			—			1			63
Distributions to noncontrolling interests		—		—			—			—			(1		)	(1		)
Distributions to unitholders		—		(111		)	(83		)	—			—			(194		)
Balance, March 31, 2018		$	500	$	6,679		$	112		$	(9	)	$	30		$	7,312

See accompanying notes to condensed consolidated financial statements.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018

(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 19 - Business Segments.

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and which is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Enbridge Inc. and its affiliates, or Enbridge. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of March 31, 2019, DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests.

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

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the SEC). Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2018 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

2. Update to Significant Accounting Policies

Our significant accounting policies are detailed in Note 2 - Summary of Significant Accounting Policies of our Annual Report on Form 10-K for the year ended December 31, 2018. Significant changes to our accounting policies as a result of Topic 842 (as defined below) are discussed below:

Leases - Our leasing activity primarily consists of transportation agreements, office space, vehicles, compressors and field equipment. We determine if an arrangement is an operating or finance lease at inception. Right of use assets represent our right to use an underlying asset for the lease term when we control the use of the asset by obtaining substantially all of the economic benefits of the asset and direct the use of the asset. Lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right of use assets and lease liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The interest rate used to calculate the present value of lease payments is the rate implicit in the lease when determinable or our incremental borrowing rate. Our incremental borrowing rate is primarily based on our collateralized borrowing rate when such borrowings exist or an estimated collateralized borrowing rate based on independent third party quotes when such borrowings do not exist. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term.

3. New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-13 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" or ASU 2016-13 - In June 2016, the FASB issued ASU 2016-13, which amends current measurement techniques used to estimate credit losses for financial assets. This ASU is effective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. We adopted this ASU on January 1, 2019 using the modified retrospective approach without application to prior periods. We implemented the following practical expedients and policy elections permitted under the new standard: (a) the package of practical expedients allowing us to not reassess whether expired or existing contracts contain a lease, the lease classification for any expired or existing leases and the treatment of initial direct costs for any expired or existing leases, (b) the land easement practical expedient, allowing us to carry forward our current accounting treatment for land easements on existing agreements, (c) not recognizing lease assets or liabilities when lease terms are less than twelve months and (d) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease.

The effect of the changes made to our consolidated January 1, 2019 balance sheet as a result of the adoption of Topic 842 was as follows:



	Balance at		Adjustments due to Topic 842			Balance at
	December 31, 2018		Adjustments due to Topic 842			January 1, 2019
	(millions)
Balance Sheet
Operating lease assets	$	—	$	84		$	84

Current liabilities:
Other	$	100	$	25		$	125
Operating lease liabilities	$	—	$	66		$	66
Other long-term liabilities	$	243	$	(7	)	$	236

This change did not have any impact on our consolidated statement of operations or consolidated statement of cash flows.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

4. Dispositions

On January 30, 2019, we entered into a purchase and sale agreement with NGL Energy Partners LP to sell Gas Supply Resources, our wholesale propane business primarily consisting of seven natural gas liquids terminals in the Eastern United States within our Logistics and Marketing segment for a purchase price of $90 million. Net proceeds received were approximately $103 million due to customary purchase price adjustments. The transaction closed effective March 1, 2019. We recognized a loss on sale of $9 million, net of goodwill, in the first quarter of 2019.

5. Revenue Recognition

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



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



	Three Months Ended March 31, 2018
	Logistics and Marketing			Gathering and Processing		Eliminations			Total
	(millions)
Sales of natural gas	$	553		$	446	$	(419	)	$	580
Sales of NGLs and condensate (a)	1,456			740		(707		)	1,489
Transportation, processing and other	14			97		—			111
Trading and marketing (losses) gains, net (b)	$	(44	)	$	3	—			(41		)
Total operating revenues	$	1,979		$	1,286	$	(1,126	)	$	2,139

(a) Includes $858 million and $793 million for the three months ended March 31, 2019 and 2018, respectively, of revenues from physical sales contracts and buy-sell exchange transactions in our logistics and marketing segment, which are not within the scope of FASB ASU 2014-09 "Revenue from Contracts with Customers" (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 $212 million as of March 31, 2019. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to be recognized through 2028 with a weighted average remaining life of 5 years as of March 31, 2019. As a practical expedient permitted by ASC 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.

6. Contract Liabilities

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

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



	March 31,
	2019
	(millions)
Balance, beginning of period	$	34
Revenue recognized (a)	—
Balance, end of period	$	34

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

The contract liabilities disclosed in the table above will be recognized as revenue as the obligations are satisfied over their average remaining contract life, which is 35 years as of March 31, 2019.

7. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

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



		Three Months Ended March 31,
		2019		2018
	(millions)
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense		$	49	$	50
General and administrative expense		$	47	$	38

Phillips 66 and its Affiliates

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

Enbridge and its Affiliates

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

Unconsolidated Affiliates

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



		Three Months Ended March 31,
		2019		2018
	(millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates		$	326	$	302
Purchases and related costs from affiliates		$	45	$	10
Operating and maintenance and general administrative expenses		$	4	$	3
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates		$	—	$	12
Purchases and related costs from affiliates		$	7	$	10
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates		$	14	$	11
Transportation, processing, and other to affiliates		$	1	$	1
Purchases and related costs from affiliates		$	219	$	145

We had balances with affiliates as follows:



	March 31, 2019		December 31, 2018
	(millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	146	$	145
Accounts payable	$	28	$	22
Enbridge (including its affiliates):
Accounts payable	$	2	$	2
Unconsolidated affiliates:
Accounts receivable	$	30	$	21
Accounts payable	$	86	$	72

8. Inventories

Inventories were as follows:



	March 31, 2019		December 31, 2018
	(millions)
Natural gas	$	23	$	34
NGLs	29		45
Total inventories	$	52	$	79

We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases and related costs in the condensed consolidated statements of operations. During the three months ended March 31, 2019, we recognized lower of cost or net realizable value adjustments of $5 million. We recognized no lower of cost or net realizable value adjustments during the three months ended March 31, 2018.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

9. Property, Plant and Equipment

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



	Depreciable Life	March 31, 2019			December 31, 2018
		(millions)
Gathering and transmission systems	20 — 50 Years	$	8,539		$	8,492
Processing, storage and terminal facilities	35 — 60 Years	5,149			5,194
Other	3 — 30 Years	571			568
Construction work in progress		527			470
Property, plant and equipment		14,786			14,724
Accumulated depreciation		(5,676		)	(5,589		)
Property, plant and equipment, net		$	9,110		$	9,135

Interest capitalized on construction projects was $5 million for the three months ended March 31, 2019 and 2018, respectively.

Depreciation expense was $101 million and $92 million for the three months ended March 31, 2019 and 2018, respectively.

10. Goodwill

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




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

11. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	March 31, 2019		December 31, 2018
		(millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,787	$	1,791
DCP Southern Hills Pipeline, LLC	66.67%	731		728
Discovery Producer Services LLC	40.00%	339		344
Front Range Pipeline LLC	33.33%	185		175
Texas Express Pipeline LLC	10.00%	98		95
Gulf Coast Express Pipeline LLC	25.00%	257		146
Mont Belvieu Enterprise Fractionator	12.50%	27		24
Panola Pipeline Company, LLC	15.00%	22		23
Mont Belvieu 1 Fractionator	20.00%	10		10
Other	Various	4		4
Total investments in unconsolidated affiliates		$	3,460	$	3,340

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Earnings from investments in unconsolidated affiliates were as follows:



	Three Months Ended March 31,
	2019		2018
	(millions)
DCP Sand Hills Pipeline, LLC	$	68	$	48
DCP Southern Hills Pipeline, LLC	23		13
Discovery Producer Services LLC	—		1
Front Range Pipeline LLC	7		5
Texas Express Pipeline LLC	5		2
Mont Belvieu Enterprise Fractionator	4		4
Mont Belvieu 1 Fractionator	4		4
Other	2		1
Total earnings from unconsolidated affiliates	$	113	$	78

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



	Three Months Ended March 31,
	2019		2018
	(millions)
Statements of operations:
Operating revenue	$	421	$	334
Operating expenses	$	191	$	139
Net income	$	231	$	194



	March 31, 2019			December 31, 2018
	(millions)
Balance sheets:
Current assets	$	327		$	411
Long-term assets	6,941			6,359
Current liabilities	(450		)	(424		)
Long-term liabilities	(249		)	(221		)
Net assets	$	6,569		$	6,125

12. Fair Value Measurement

Valuation Hierarchy

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


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


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


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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

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

Commodity Derivative Assets and Liabilities

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

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

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

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

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, equity investments in unconsolidated affiliates, and intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

The following table presents the financial instruments carried at fair value as of March 31, 2019 and December 31, 2018, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:



	March 31, 2019												December 31, 2018
	Level 1			Level 2			Level 3			Total Carrying Value			Level 1			Level 2			Level 3			Total Carrying Value
	(millions)
Current assets:
Commodity derivatives (a)	$	16		$	14		$	5		$	35		$	62		$	32		$	14		$	108
Long-term assets:
Commodity derivatives (b)	$	—		$	1		$	1		$	2		$	4		$	2		$	2		$	8
Current liabilities:
Commodity derivatives (c)	$	(14	)	$	(46	)	$	(1	)	$	(61	)	$	(39	)	$	(52	)	$	—		$	(91	)
Long-term liabilities:
Commodity derivatives (d)	$	—		$	(4	)	$	(1	)	$	(5	)	$	(1	)	$	(5	)	$	(2	)	$	(8	)


(a)	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.


(b)	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.


(c)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.


(d)	Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets.

Changes in Levels 1 and 2 Fair Value Measurements

The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as “Transfers into or out of Level 1 and Level 2”. During the three months ended March 31, 2019 and 2018, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.

Changes in Level 3 Fair Value Measurements

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

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(millions)
Three months ended March 31, 2019 (a):
Beginning balance	$	14		$	2		$	—		$	(2	)
Net unrealized (losses) gains included in earnings (b)	(4		)	(1		)	(2		)	1
Transfers out of Level 3 (c)	(2		)	—			—			—
Settlements	(3		)	—			1			—
Ending balance	$	5		$	1		$	(1	)	$	(1	)
Net unrealized losses on derivatives still held included in earnings (b)	$	—		$	—		$	(1	)	$	(1	)
Three months ended March 31, 2018 (a):
Beginning balance	$	3		$	1		$	(13	)	$	(1	)
Net unrealized (losses) gains included in earnings (b)	—			(1		)	4			(2		)
Transfers out of Level 3 (c)	—			—			2			—
Settlements	(1		)	—			1			—
Ending balance	$	2		$	—		$	(6	)	$	(3	)
Net unrealized (losses) gains on derivatives still held included in earnings (b)	$	—		$	(1	)	$	2		$	(2	)


(a)	There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three months ended March 31, 2019 and 2018.


(b)	Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net.


(c)	Amounts transferred out of Level 3 are reflected at fair value at the end of the period.

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

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



	March 31, 2019
Product Group	Fair Value			Forward Curve Range
	(millions)
Assets
NGLs	$	5		$0.24-$1.24	Per gallon
Natural gas	$	1		$1.95-$2.58	Per MMBtu
Liabilities
NGLs	$	(1	)	$0.13-$1.24	Per gallon
Natural gas	$	(1	)	$2.42-$2.86	Per MMBtu

Estimated Fair Value of Financial Instruments

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

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

We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. The fair value of borrowings under the Credit Agreement (defined below) and the accounts receivable securitization facility (the Securitization Facility) are based on carrying value, which approximates fair value as their interest rates are based on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of March 31, 2019 and December 31, 2018, the carrying value and fair value of our total debt, including current maturities, were as follows:



		March 31, 2019				December 31, 2018
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(millions)

Total debt		$	5,391	$	5,476	$	5,337	$	5,170

(a) Excludes unamortized issuance costs.

13. Leases

We have operating leases for transportation agreements, office space, vehicles, compressors and field equipment. Our leases have remaining lease terms of less than 1 year to 22 years, some of which may include options to extend leases up to 20 years, and some of which may include options to terminate the leases in less than one year. Extension options on certain compressors and field equipment are included in the lease terms used to calculate our operating lease assets and liabilities as it is reasonably certain that we will exercise those options. We do not have any finance leases as of March 31, 2019. Operating leases are included in operating lease assets, other current liabilities and operating lease liabilities on our condensed consolidated balance sheet as of March 31, 2019 as follows:



	As of
	March 31, 2019
	(millions)
Operating lease assets	$	78

Operating lease liabilities	$	66
Other current liabilities	18
Total	$	84

The components of lease expense, including variable lease costs primarily consisting of common area maintenance on our office spaces and variable transportation costs, are as follows:



	Three months ended
	March 31, 2019
	(millions)
Operating lease cost	$	6
Variable lease cost	2
Short term lease cost	1
Total lease cost	$	9

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Maturities of operating lease liabilities under non-cancelable leases as of March 31, 2019 are as follows:



	Three months ended
	March 31, 2019
	(millions)
2019 - remainder	$	16
2020	22
2021	20
2022	15
2023	9
Thereafter	11
Total lease payments	$	93
Less imputed interest	(9		)
Total operating lease liabilities	$	84

Minimum rental payments under our various operating leases in the year indicated were as follows as of December 31, 2018:



	Future Minimum Rental Payments as of December 31, 2018
	(millions)
2019	$	22
2020	18
2021	14
2022	9
2023	5
Thereafter	7
Total minimum rental payments	$	75

Consolidated rental expense totaled $8 million for the three months ended March 31, 2018.

Supplemental cash flow information related to leases as follows:



	Three months ended
	March 31, 2019
	(millions)
Cash paid for amounts included in the measurement of operating lease liabilities:	$	6
Right-of-use assets obtained in exchange for operating lease obligations following the adoption of Topic 842:	$	6

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

14. Debt



	March 31, 2019			December 31, 2018
	(millions)
Senior notes:
Issued March 2014, interest at 2.700% payable semi-annually, due April 2019	325			325
Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)	600			600
Issued September 2011, interest at 4.750% payable semiannually, due September 2021	500			500
Issued March 2012, interest at 4.950% payable semi-annually, due April 2022	350			350
Issued March 2013, interest at 3.875% payable semi-annually, due March 2023	500			500
Issued July 2018 and January 2019, interest at 5.375% payable semi-annually, due July 2025	825			500
Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)	300			300
Issued October 2006, interest at 6.450% payable semi-annually, due November 2036	300			300
Issued September 2007, interest at 6.750% payable semi-annually, due September 2037	450			450
Issued March 2014, interest at 5.600% payable semi-annually, due April 2044	400			400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043	550			550
Credit agreement:
Revolving credit facility, weighted-average variable interest rate of 3.950%, as of March 31, 2019, due December 2022	80			351
Accounts receivable securitization facility:
Accounts receivable securitization facility, weighted-average variable interest rate of 3.290% as of March 31, 2019, due August 2019	200			200
Fair value adjustments related to interest rate swap fair value hedges (a)	20			21
Unamortized issuance costs	(30		)	(30		)
Unamortized discount	(9		)	(10		)
Total debt	5,361			5,307
Current debt	1,125			525
Total long-term debt	$	4,236		$	4,782

(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately

$20 million related to the swaps is being amortized as a reduction to interest expense through 2020 and 2030, the original maturity dates of the debt.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Accounts Receivable Securitization Facility

In August 2018, we entered into our Securitization Facility that provides up to $200 million of borrowing capacity through August 2019 at LIBOR market index rates plus a margin. Under this Securitization Facility, certain of the Partnership’s wholly owned subsidiaries sell or contribute receivables to another of the Partnership’s consolidated subsidiaries, DCP Receivables LLC (“DCP Receivables”), a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility.

DCP Receivables’ sole activity consists of purchasing receivables from the Partnership’s wholly owned subsidiaries that participate in the Securitization Facility and providing these receivables as collateral for DCP Receivables’ borrowings under the Securitization Facility. DCP Receivables is a separate legal entity and the accounts receivable of DCP Receivables, up to the amount of the outstanding debt under the Securitization Facility, are not available to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. Any excess receivables are eligible to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. As of March 31, 2019, DCP Receivables had $766 million of our accounts receivable securing borrowings of $200 million under its Securitization Facility. Borrowings under the Securitization Facility are included in “Current debt” on the condensed consolidated balance sheet.

Senior Notes Issuance

On January 18, 2019, we issued an additional $325 million of aggregate principal amount of our existing $500 million 5.375% Senior Notes due July 2025. We received proceeds of $324 million, net of underwriters’ fees, related expenses and issuance premiums, which we used for general partnership purposes including the funding of capital expenditures and repayment of outstanding indebtedness under the Credit Agreement. The full $825 million of our 5.375% Senior Notes due July 2025 is treated as a single series of debt. The 2025 notes will mature on July 15, 2025 unless redeemed prior to maturity. Interest on the 2025 notes is payable semi-annually in arrears on January 15 and July 15 of each year.

Credit Agreement

We are a party to a $1.4 billion unsecured revolving Credit Agreement (the "Credit Agreement") which matures on December 6, 2022. The Credit Agreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million, subject to requisite lender approval. The Credit Agreement may be extended for up to two additional one-year periods subject to requisite lender approval. Loans under the Credit Agreement may be used for working capital and other general partnership purposes including acquisitions.

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

Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.45% based on our current credit rating. The Credit Agreement incurs an annual facility fee of 0.30% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.4 billion revolving credit facility.

As of March 31, 2019, we had unused borrowing capacity of $1,307 million, net of $13 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by the unused borrowing capacity of $1,307 million as of March 31, 2019. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the December 6, 2022 maturity date.

Senior Notes and Junior Subordinated Notes

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

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

The maturities of our debt as of March 31, 2019 are as follows:



	Debt Maturities
	(millions)
2019	$	525
2020	600
2021	500
2022	430
2023	500
Thereafter	2,825
Total debt	$	5,380

15. Risk Management and Hedging Activities

Our operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee (the Risk Management Committee), to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

Collateral

As of March 31, 2019, we had cash deposits of $64 million, included in collateral cash deposits in our condensed consolidated balance sheets. Additionally, as of March 31, 2019, we held letters of credit of $59 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Offsetting

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



	March 31, 2019								December 31, 2018
	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	$	37		$	—	$	37		$	116		$	—	$	116
Liabilities:
Commodity derivatives	$	(66	)	$	—	$	(66	)	$	(99	)	$	—	$	(99	)

Summarized Derivative Information

The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2019 and December 31, 2018.



Balance Sheet Line Item	March 31, 2019		December 31, 2018		Balance Sheet Line Item	March 31, 2019			December 31, 2018
	(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	$	35	$	108	Unrealized losses on derivative instruments — current	$	(61	)	$	(91	)
Unrealized gains on derivative instruments — long-term	2		8		Unrealized losses on derivative instruments — long-term	(5		)	(8		)
Total	$	37	$	116	Total	$	(66	)	$	(99	)

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



	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)	$	—		$	—	$	(1	)

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

(a)Relates to Discovery Producer Services LLC ("Discovery"), an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2018:



	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)	$	(6	)	$	1	$	(9	)
Net deferred (losses) gains in AOCI (ending balance)	$	(4	)	$	(6	)	$	1	$	(9	)


(a)	Relates to Discovery, an unconsolidated affiliate.

For the three months ended March 31, 2019 and 2018, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2019 and 2018, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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



Commodity Derivatives: Statements of Operations Line Item		Three Months Ended March 31,
		2019			2018
	(millions)
Realized gains (losses)		$	27		$	(12	)
Unrealized losses		(54		)	(29		)
Trading and marketing losses, net		$	(27	)	$	(41	)

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

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



	March 31, 2019
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net Short Position (Bbls)		Net Long (Short) Position (MMBtu)
2019	(1,191,000	)	(32,148,650	)	(26,987,090	)	2,102,500
2020	(283,000	)	(930,000	)	(14,388,830	)	3,660,000
2021	(100,000	)	—		(5,516,168	)	(3,650,000	)
2022	—		—		(175	)	—

	March 31, 2018
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net (Short) Long Position (MMBtu)
2018	(2,511,000	)	(20,737,300	)	(24,473,245	)	(3,850,000	)
2019	(650,000	)	—		(3,240,167	)	2,402,500
2020	—		—		231,548		3,660,000

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

16. Partnership Equity and Distributions

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

Distributions — The following table presents our cash distributions paid in 2019 and 2018:



Payment Date	Per Unit Distribution		Total Cash Distribution
			(millions)
Distributions to common unitholders
February 14, 2019	$	0.7800	$	154
November 14, 2018	$	0.7800	$	155
August 14, 2018	$	0.7800	$	154
May 15, 2018	$	0.7800	$	155
February 14, 2018	$	0.7800	$	194

Distributions to Series A Preferred unitholders
December 17, 2018	$	36.8750	$	18
June 15, 2018	$	41.9965	$	21

Distributions to Series B Preferred unitholders
March 15, 2019	$	0.4922	$	3
December 17, 2018	$	0.4922	$	3
September 17, 2018	$	0.6781	$	4

Distributions to Series C Preferred unitholders
January 15, 2019	$	0.5576	$	2

17. Net Income or Loss per Limited Partner Unit

Basic and diluted net income or loss per limited partner unit (LPU) is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of LPUs outstanding during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of potential dilutive units outstanding during the period using the two-class method.

18. Commitments and Contingent Liabilities

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

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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

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

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

•

In March 2018, the New Mexico Environment Department ("NMED") issued two separate Notices of Violation ("NOV") relating to upset and malfunction event emissions at two of our gas processing plants. Following information exchanges and discussions with NMED regarding the events and the propriety of the alleged violations, on February 14, 2019 we entered into preliminary settlement agreements to resolve the alleged violations under each NOV for administrative penalties in the amount of $149,832 and $142,233, respectively. We intend to mitigate a portion of each administrative penalty through the implementation of environmentally beneficial projects.

•

In April 2018, the Colorado Department of Public Health and Environment ("CDPHE") issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants that we self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, during the first quarter of 2019, a resolution was proposed pursuant to which the plant's air permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as an economic benefit payment generally covering the period when the flare was required to be included in the facility air permit, in a combined amount expected to be between approximately $375,000 and $420,000. We are still evaluating and holding discussions with CDPHE as to the foregoing amounts and proposed settlement terms.

19. Business Segments

Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 of the Notes to Consolidated Financial Statements in “Financial Statements and Supplementary Data” included as Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2018.

Our Logistics and Marketing segment includes transporting, trading, marketing, storing natural gas and NGLs, and fractionating NGLs. The operations of our wholesale propane business were included in our Logistics and Marketing segment through March 1, 2019. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

gas, producing and fractionating NGLs, and recovering condensate. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminations column.

The following tables set forth our segment information:

Three Months Ended March 31, 2019:



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

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

Three Months Ended March 31, 2018:



	Logistics and Marketing			Gathering and Processing			Other			Eliminations			Total
	(millions)
Total operating revenue	$	1,979		$	1,286		$	—		$	(1,126	)	$	2,139
Gross margin (a)	$	18		$	352		$	—		$	—		$	370
Operating and maintenance expense	(11		)	(148		)	(3		)	—			(162		)
Depreciation and amortization expense	(3		)	(84		)	(7		)	—			(94		)
General and administrative expense	(3		)	(4		)	(52		)	—			(59		)
Other income (expense)	1			(3		)	—			—			(2		)
Earnings from unconsolidated affiliates	77			1			—			—			78
Interest expense	—			—			(67		)	—			(67		)
Income tax expense	—			—			(1		)	—			(1		)
Net income (loss)	$	79		$	114		$	(130	)	$	—		$	63
Net income attributable to noncontrolling interests	—			(1		)	—			—			(1		)
Net income (loss) attributable to partners	$	79		$	113		$	(130	)	$	—		$	62
Non-cash derivative mark-to-market (b)	$	(43	)	$	14		$	—		$	—		$	(29	)
Capital expenditures	$	1		$	120		$	3		$	—		$	124
Investments in unconsolidated affiliates, net	$	59		$	1		$	—		$	—		$	60



	March 31,		December 31,
	2019		2018
	(millions)
Segment long-term assets:
Gathering and Processing	$	9,126	$	9,058
Logistics and Marketing	3,692		3,661
Other (c)	287		276
Total long-term assets	13,105		12,995
Current assets	1,082		1,271
Total assets	$	14,187	$	14,266

(a)

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


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


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

20. Supplemental Cash Flow Information

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Three Months Ended March 31,
	2019		2018
	(millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	65	$	84
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	40	$	54
Other non-cash activities:
Operating lease assets arising from the implementation of Topic 842	$	84	$	—

21. Supplementary Information - Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Balance Sheets
	March 31, 2019
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			914			—			914
Inventories	—		—			52			—			52
Other	—		—			115			—			115
Total current assets	—		—			1,082			—			1,082
Property, plant and equipment, net	—		—			9,110			—			9,110
Goodwill and intangible assets, net	—		—			271			—			271
Advances receivable — consolidated subsidiaries	2,293		1,870			—			(4,163		)	—
Investments in consolidated subsidiaries	4,893		8,255			—			(13,148		)	—
Investments in unconsolidated affiliates	—		—			3,460			—			3,460
Other long-term assets	—		—			264			—			264
Total assets	$	7,186	$	10,125		$	14,187		$	(17,311	)	$	14,187
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	2	$	71		$	1,206		$	—		$	1,279
Current maturities of long-term debt	—		925			200			—			1,125
Advances payable — consolidated subsidiaries	—		—			4,163			(4,163		)	—
Long-term debt	—		4,236			—			—			4,236
Other long-term liabilities	—		—			334			—			334
Total liabilities	2		5,232			5,903			(4,163		)	6,974
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	7,184		4,896			8,260			(13,148		)	7,192
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	7,184		4,893			8,255			(13,148		)	7,184
Noncontrolling interests	—		—			29			—			29
Total equity	7,184		4,893			8,284			(13,148		)	7,213
Total liabilities and equity	$	7,186	$	10,125		$	14,187		$	(17,311	)	$	14,187

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Balance Sheets
	December 31, 2018
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			1,033			—			1,033
Inventories	—		—			79			—			79
Other	—		—			158			—			158
Total current assets	—		—			1,271			—			1,271
Property, plant and equipment, net	—		—			9,135			—			9,135
Goodwill and intangible assets, net	—		—			328			—			328
Advances receivable — consolidated subsidiaries	2,452		1,883			—			(4,335		)	—
Investments in consolidated subsidiaries	4,818		8,113			—			(12,931		)	—
Investments in unconsolidated affiliates	—		—			3,340			—			3,340
Other long-term assets	—		—			192			—			192
Total assets	$	7,270	$	9,996		$	14,266		$	(17,266	)	$	14,266
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	2	$	71		$	1,306		$	—		$	1,379
Current maturities of long-term debt	—		325			200			—			525
Advances payable — consolidated subsidiaries	—		—			4,335			(4,335		)	—
Long-term debt	—		4,782			—			—			4,782
Other long-term liabilities	—		—			283			—			283
Total liabilities	2		5,178			6,124			(4,335		)	6,969
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	7,268		4,821			8,118			(12,931		)	7,276
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	7,268		4,818			8,113			(12,931		)	7,268
Noncontrolling interests	—		—			29			—			29
Total equity	7,268		4,818			8,142			(12,931		)	7,297
Total liabilities and equity	$	7,270	$	9,996		$	14,266		$	(17,266	)	$	14,266

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2019
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	2,111		$	—		$	2,111
Transportation, processing and other	—		—			115			—			115
Trading and marketing losses, net	—		—			(27		)	—			(27		)
Total operating revenues	—		—			2,199			—			2,199
Operating costs and expenses:
Purchases and related costs	—		—			1,804			—			1,804
Operating and maintenance expense	—		—			178			—			178
Depreciation and amortization expense	—		—			103			—			103
General and administrative expense	—		—			67			—			67
Loss on sale of assets, net	—		—			9			—			9
Other expense, net	—		—			5			—			5
Total operating costs and expenses	—		—			2,166			—			2,166
Operating income	—		—			33			—			33
Interest expense, net	—		(67		)	(2		)	—			(69		)
Income from consolidated subsidiaries	75		142			—			(217		)	—
Earnings from unconsolidated affiliates	—		—			113			—			113
Income before income taxes	75		75			144			(217		)	77
Income tax expense	—		—			(1		)	—			(1		)
Net income	75		75			143			(217		)	76
Net income attributable to noncontrolling interests	—		—			(1		)	—			(1		)
Net income attributable to partners	$	75	$	75		$	142		$	(217	)	$	75



	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended March 31, 2019
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
Net income	$	75	$	75	$	143		$	(217	)	$	76
Other comprehensive income:
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	75		75		143			(217		)	76
Total comprehensive income attributable to noncontrolling interests	—		—		(1		)	—			(1		)
Total comprehensive income attributable to partners	$	75	$	75	$	142		$	(217	)	$	75

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2018
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	2,069		$	—		$	2,069
Transportation, processing and other	—		—			111			—			111
Trading and marketing losses, net	—		—			(41		)	—			(41		)
Total operating revenues	—		—			2,139			—			2,139
Operating costs and expenses:
Purchases and related costs	—		—			1,769			—			1,769
Operating and maintenance expense	—		—			162			—			162
Depreciation and amortization expense	—		—			94			—			94
General and administrative expense	—		—			59			—			59
Other expense, net	—		—			2			—			2
Total operating costs and expenses	—		—			2,086			—			2,086
Operating income	—		—			53			—			53
Interest expense, net	—		(67		)	—			—			(67		)
Income from consolidated subsidiaries	62		129			—			(191		)	—
Earnings from unconsolidated affiliates	—		—			78			—			78
Income before income taxes	62		62			131			(191		)	64
Income tax expense	—		—			(1		)	—			(1		)
Net income	62		62			130			(191		)	63
Net income attributable to noncontrolling interests	—		—			(1		)	—			(1		)
Net income attributable to partners	$	62	$	62		$	129		$	(191	)	$	62



	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended March 31, 2018
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
Net income	$	62	$	62	$	130		$	(191	)	$	63
Other comprehensive income:
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	62		62		130			(191		)	63
Total comprehensive income attributable to noncontrolling interests	—		—		(1		)	—			(1		)
Total comprehensive income attributable to partners	$	62	$	62	$	129		$	(191	)	$	62

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Statement of Cash Flows
	Three Months Ended March 31, 2019
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(66	)	$	383		$	—		$	317
INVESTING ACTIVITIES:
Intercompany transfers	159			13			—			(172		)	—
Capital expenditures	—			—			(182		)	—			(182		)
Investments in unconsolidated affiliates, net	—			—			(131		)	—			(131		)
Proceeds from sale of assets	—			—			103			—			103
Net cash provided by (used in) investing activities	159			13			(210		)	(172		)	(210		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(172		)	172			—
Proceeds from debt	—			1,402			—			—			1,402
Payments of debt	—			(1,348		)	—			—			(1,348		)
Distributions to preferred limited partners	(5		)	—			—			—			(5		)
Distributions to limited partners and general partner	(154		)	—			—			—			(154		)
Distributions to noncontrolling interests	—			—			(1		)	—			(1		)
Other	—			(1		)	—			—			(1		)
Net cash (used in) provided by financing activities	(159		)	53			(173		)	172			(107		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents, beginning of period	—			—			1			—			1
Cash and cash equivalents, end of period	$	—		$	—		$	1		$	—		$	1

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)



	Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(84	)	$	206		$	—		$	122
INVESTING ACTIVITIES:
Intercompany transfers	194			(171		)	—			(23		)	—
Capital expenditures	—			—			(124		)	—			(124		)
Investments in unconsolidated affiliates, net	—			—			(60		)	—			(60		)
Proceeds from sale of assets	—			—			3			—			3
Net cash provided by (used in) investing activities	194			(171		)	(181		)	(23		)	(181		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(23		)	23			—
Proceeds from long-term debt	—			635			—			—			635
Payments of debt	—			(535		)	—			—			(535		)
Distributions to limited partners and general partner	(194		)	—			—			—			(194		)
Distributions to noncontrolling interests	—			—			(1		)	—			(1		)
Net cash (used in) provided by financing activities	(194		)	100			(24		)	23			(95		)
Net change in cash and cash equivalents	—			(155		)	1			—			(154		)
Cash and cash equivalents, beginning of period	—			155			1			—			156
Cash and cash equivalents, end of period	$	—		$	—		$	2		$	—		$	2

DCP MIDSTREAM, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2019 and 2018 (Continued)

(Unaudited)

22. Subsequent Events

On April 23, 2019, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.78 per common unit. The distribution will be paid on May 15, 2019 to unitholders of record on May 3, 2019.

On the same date, we announced that the board of directors of the General Partner declared a semi-annual distribution on our Series A Preferred Units of $36.8750 per unit. The distribution will be paid on June 17, 2019 to unitholders of record on June 3, 2019.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and $0.4969 per unit, respectively. The Series B distributions will be paid on June 17, 2019 to unitholders of record on June 3, 2019. The Series C distribution will be paid on July 15, 2019 to unitholders of record on July 1, 2019.

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, 2018.

Overview

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

General Trends and Outlook

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

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

In the long-term, our belief is that commodity prices will continue to be at levels which support growth in crude, condensate, natural gas, and NGL production. We expect future commodity prices will be influenced by the severity of winter and summer weather, tariffs and other global economic conditions, the level of North American production and drilling activity by exploration and production companies and the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil.

Our business is primarily driven by the level of production of natural gas by producers and of NGLs from processing plants connected to our pipelines and fractionators. These volumes can be affected by, among other things, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection.

NGL prices are impacted by the balance of supply and demand from petrochemical and refining industries and export facilities. The petrochemical industry has been making significant investment in building, expanding and converting facilities to use lighter NGL-based feedstocks, including ethane in their chemical plants. As these facilities commence operations, ethane demand is expected to increase which could provide price support for increased recovery of ethane at gas processing plants. We believe these new facilities will cause increased demand over time, which should provide support for the increasing supply of ethane. In addition, export facilities are being expanded and built, which provide support for the increasing supply of NGLs. Although there can be, and has been, volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.

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

Recent supply growth has resulted in industry wide infrastructure constraints at pipeline and fractionation facilities. We believe we are well positioned to manage through these constraints as a large, integrated midstream company, but growth of our business could be dampened in the near term while more industry wide pipeline and fractionation facilities are developed. Although there may be infrastructure constraints in the near term, we believe our growth projects and other industry wide projects coming on-line over the next two years will help mitigate those constraints. We believe these projects being developed will enable us to meet the demand of our customers.

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 while the remainder do not.

In addition to the U.S. financial markets, many businesses and investors continue to monitor global economic conditions. Uncertainty abroad may contribute to volatility in domestic financial and commodity markets.

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


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


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


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


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


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


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

During 2019, our strategic objectives will continue to focus on maintaining stable Distributable Cash Flows from our existing assets and executing on opportunities to sustain and ultimately grow our long-term Distributable Cash Flows. We believe the key elements to stable Distributable Cash Flows are the diversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our hedged commodity position, the objective of which is to protect against downside risk in our Distributable Cash Flows.

We have engaged in a disciplined growth strategy in recent years focusing on our key areas of operations. Our targeted strategy may take numerous forms such as organic build opportunities within our footprint, joint venture opportunities, and acquisitions. Growth opportunities will be evaluated in cooperation with producers and customers based on the expected level of drilling activity in these geographic regions and the impacts of higher costs of capital.

Some of our growth projects include the following:


•	Within our Logistics and Marketing segment, we are participating in the Front Range 100 MBbls/d and Texas Express 90 MBbls/d expansions adding NGL takeaway from the DJ Basin. Both expansions are expected to go into service in the third quarter of 2019.


•	We have a 33% ownership option in the Cheyenne Connector pipeline. The Cheyenne Connector pipeline will have an initial capacity of at least 600 MMcf/day and is expected to be in service in the fourth quarter of 2019, subject to certain conditions, including required approvals from the Federal Energy Regulatory Commission.


•	We are adding NGL takeaway to the DJ Basin with our Southern Hills pipeline extension with capacity of 90 MBbls/d, expandable to 120 MBbls/d. Expected completion is in the fourth quarter of 2019.


•	We have a 25% ownership interest in the Gulf Coast Express pipeline, or "GCX". The GCX project is designed to transport approximately 2 Bcf/d of natural gas, and is fully subscribed. The natural gas takeaway pipeline is under construction and is anticipated to be in-service in the fourth quarter of 2019.


•	We hold an option to acquire a 30% ownership interest in two 150 MBbls/d fractionators to be constructed within Phillips 66's Sweeny Hub, exercisable at the in-service date, which is expected to be in late 2020.

•

Within our Gathering and Processing Segment, construction of our up to 300 MMcf/d O'Connor 2 facility and associated gathering infrastructure, located in the DJ Basin, is progressing. O'Connor 2 is comprised of 200 MMcf/d of processing capacity and up to 100 MMcf/d of bypass. We expect to place the plant into service at the end of the second quarter of 2019, and the bypass into service in the third quarter of 2019.


•	The first phase of the Bighorn program is under development with focus on adding 200-300 MMcf/d of gas processing capacity to the DJ Basin by mid 2020.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2019 plan includes maintenance capital expenditures of between $90 million and $110 million, and expansion capital expenditures of between $600 million and $800 million. Expansion capital expenditures are expected to include the construction of the O'Connor 2 facility in our DJ Basin as well as the construction of the Gulf Coast Express pipeline, the Front Range and Texas Express expansions and the extension of Southern Hills into the DJ Basin, which are shown as investments in unconsolidated affiliates in our condensed consolidated statements of cash flows.

Recent Events

Sale of Wholesale Propane Business

Issuance of Senior Notes

Common and Preferred Distributions

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2019 and 2018. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



		Three Months Ended March 31,						Variance 2019 vs. 2018
		2019			2018			Increase (Decrease)			Percent
	(millions, except operating data)
Operating revenues (a):
Logistics and Marketing		$	2,045		$	1,979		$	66		3	%
Gathering and Processing		1,288			1,286			2			—	%
Inter-segment eliminations		(1,134		)	(1,126		)	8			1	%
Total operating revenues		2,199			2,139			60			3	%
Purchases and related costs
Logistics and Marketing		(1,987		)	(1,961		)	26			1	%
Gathering and Processing		(951		)	(934		)	17			2	%
Inter-segment eliminations		1,134			1,126			8			1	%
Total purchases		(1,804		)	(1,769		)	35			2	%
Operating and maintenance expense		(178		)	(162		)	16			10	%
Depreciation and amortization expense		(103		)	(94		)	9			10	%
General and administrative expense		(67		)	(59		)	8			14	%
Other expense, net		(5		)	(2		)	3			*
Loss on sale of assets, net		(9		)	—			9			*
Earnings from unconsolidated affiliates (b)		113			78			35			45	%
Interest expense		(69		)	(67		)	2			3	%
Income tax expense		(1		)	(1		)	—			—	%
Net income attributable to noncontrolling interests		(1		)	(1		)	—			—	%
Net income attributable to partners		$	75		$	62		$	13		21	%
Other data:
Gross margin (c):
Logistics and Marketing		$	58		$	18		$	40		*
Gathering and Processing		337			352			(15		)	(4	)%
Total gross margin		$	395		$	370		$	25		7	%

Non-cash commodity derivative mark-to-market		$	(54	)	$	(29	)	$	(25	)	*
NGL pipelines throughput (MBbls/d) (d)		668			519			149			29	%
Natural gas wellhead (MMcf/d) (d)		4,938			4,467			471			11	%
NGL gross production (MBbls/d) (d)		436			384			52			14	%

* Percentage change is not meaningful.


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


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


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


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

Three Months Ended March 31, 2019 vs. Three Months Ended March 31, 2018

Total Operating Revenues — Total operating revenues increased $60 million in 2019 compared to 2018 primarily as a result of the following:


•	$66 million increase for our Logistics and Marketing segment primarily due to higher gas and NGL sales volumes, which impacted both sales and purchases, higher natural gas prices and favorable commodity derivative activity, partially offset by lower NGL and crude prices; and

•

$2 million increase for our Gathering and Processing segment primarily due to increased volume from growth projects related to our DJ Basin system in the North region, increased volumes in the Permian region, increased drilling activity in our Eagle Ford system in the South region and higher natural gas prices, which impacted both sales and purchases, partially offset by lower NGL and crude prices and unfavorable commodity derivative activity;

These increases were partially offset by:


•	$8 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher gas and NGL sales volumes partially offset by lower commodity prices.

Total Purchases — Total purchases increased $35 million in 2019 compared to 2018 primarily as a result of the following:


•	$26 million increase for our Logistics and Marketing segment for the reasons discussed above.


•	$17 million increase for our Gathering and Processing segment for the reasons discussed above;

These increases were partially offset by:


•	$8 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher gas and NGL sales volumes offset by lower commodity prices.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2019 compared to 2018 primarily as a result of increased base operating costs driven by new compressor leases and reliability improvements, increased property taxes and planned spending associated with volume growth.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2019 compared to 2018 due to growth projects related to our DJ Basin system and accelerated depreciation on certain property, plant and equipment in our Midcontinent region.

General and Administrative Expense — General and administrative expense increased in 2019 compared to 2018 primarily as a result of increased employee related costs.

Other Expense, net — Other expense in 2019 represents the write-off of property, plant and equipment.

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

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2019 compared to 2018 primarily as a result of higher throughput volumes on the Sand Hills and Southern Hills NGL pipelines due to increased capacity.

Net Income Attributable to Partners — Net income attributable to partners increased in 2019 compared to 2018 for the reasons discussed above.

Gross Margin — Gross margin increased $25 million in 2019 compared to 2018 primarily as a result of the following:


•	$40 million increase for our Logistics and Marketing segment primarily related to favorable commodity derivative activity and higher gas marketing margins due to favorable commodity spreads primarily associated with Guadalupe, partially offset by lower gas storage margins and a 2019 inventory valuation adjustment;

These increases were partially offset by:


•	$15 million decrease for our Gathering and Processing segment primarily related to unfavorable commodity derivative activity and lower commodity prices, partially offset by increased volume from growth projects related to our DJ Basin system in the North region, increased volumes in the Permian region and increased drilling activity in our Eagle Ford system in the South region.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

Earnings from investments in unconsolidated affiliates were as follows:



		Three Months Ended March 31,
		2019		2018
	(millions)
DCP Sand Hills Pipeline, LLC		$	68	$	48
DCP Southern Hills Pipeline, LLC		23		13
Front Range Pipeline LLC		7		5
Texas Express Pipeline LLC		5		2
Mont Belvieu Enterprise Fractionator		4		4
Mont Belvieu 1 Fractionator		4		4
Discovery Producer Services LLC		—		1
Other		2		1
Total earnings from unconsolidated affiliates		$	113	$	78

Distributions received from unconsolidated affiliates were as follows:



		Three Months Ended March 31,
		2019		2018
	(millions)
DCP Sand Hills Pipeline, LLC		$	76	$	49
DCP Southern Hills Pipeline, LLC		25		16
Front Range Pipeline LLC		6		6
Texas Express Pipeline LLC		5		5
Mont Belvieu Enterprise Fractionator		1		3
Mont Belvieu 1 Fractionator		5		3
Discovery Producer Services LLC		5		8
Other		1		1
Total distributions from unconsolidated affiliates		$	124	$	91

Results of Operations — Logistics and Marketing Segment



Operating Data
				Three Months Ended March 31, 2019
System	Approximate System Length (Miles)	Fractionators	Approximate Throughput Capacity (MBbls/d) (a)	Pipeline Throughput (MBbls/d) (a)	Fractionator Throughput (MBbls/d) (a)
Sand Hills pipeline	1,500	—	334	330	—
Southern Hills pipeline	950	—	128	106	—
Front Range pipeline	450	—	50	47	—
Texas Express pipeline	600	—	28	22	—
Other NGL pipelines (a)	1,200	—	241	163	—
Pipelines total	4,700	—	781	668	—

Mont Belvieu fractionators	—	2	60	—	64
Fractionators total	—	2	60	—	64


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

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



		Three Months Ended March 31,						Variance 2019 vs. 2018
		2019			2018			Increase (Decrease)			Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	2,040		$	2,009		$	31		2	%
Transportation, processing and other		12			14			(2		)	(14	)%
Trading and marketing losses, net		(7		)	(44		)	37			84	%
Total operating revenues		2,045			1,979			66			3	%
Purchases and related costs		(1,987		)	(1,961		)	26			1	%
Operating and maintenance expense		(9		)	(11		)	(2		)	(18	)%
Depreciation and amortization expense		(3		)	(3		)	—			—	%
General and administrative expense		(3		)	(3		)	—			—	%
Other income, net		—			1			(1		)	*
Earnings from unconsolidated affiliates (a)		113			77			36			47	%
Loss on sale of assets, net		(9		)	—			9			—
Segment net income attributable to partners		$	147		$	79		$	68		86	%
Other data:
Segment gross margin (b)		$	58		$	18		$	40		*
Non-cash commodity derivative mark-to-market		$	(18	)	$	(43	)	$	25		58	%
NGL pipelines throughput (MBbls/d) (c)		668			519			149			29	%

* Percentage change is not meaningful.


(a)	Earnings from unconsolidated affiliates for Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of our investments and the underlying equity of the entities.


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


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

Three Months Ended March 31, 2019 vs. Three Months Ended March 31, 2018

Total Operating Revenues — Total operating revenues increased $66 million in 2019 compared to 2018, primarily as a result of the following:


•	$351 million increase attributable to higher gas and NGL sales volumes, which impacted both sales and purchases;


•	$37 million increase as a result of commodity derivative activity attributable to an decrease in unrealized cash settlement losses of $25 million and an increase in realized cash settlement gains of $12 million due to movements in forward prices of commodities in 2019; and

These increases were partially offset by:


•	$320 million decrease as a result of lower NGL and crude prices, partially offset by higher natural gas prices, which impacted both sales and purchases, before the impact of derivative activity.

Purchases and Related Costs — Purchases and related costs increased $26 million in 2019 compared to 2018, primarily as a result of higher gas and NGL sales volumes and higher natural gas prices, partially offset by lower NGL and crude prices.

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

Segment Gross Margin — Segment gross margin increased $40 million in 2019 compared to 2018, primarily as a result of the following:


•	$37 million increase as a result of commodity derivative activity discussed above, and;


•	$20 million increase in gas marketing margins due to favorable commodity spreads primarily associated with Guadalupe;

These increases are partially offset by;


•	$17 million decrease as a result of lower gas storage margins and a 2019 inventory valuation adjustment.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2019 compared to 2018 primarily as a result of higher throughput volumes on the Sand Hills and Southern Hills NGL pipelines due to increased capacity.

Results of Operations — Gathering and Processing Segment



Operating Data
				Three Months Ended March 31, 2019
Regions	Plants	Approximate Gathering and Transmission Systems (Miles)	Approximate Net Nameplate Plant Capacity (MMcf/d) (a)	Natural Gas Wellhead Volume (MMcf/d) (a)	NGL Production (MBbls/d) (a)
North	13	4,000	1,390	1,391	106
Permian	11	16,500	1,260	943	113
Midcontinent	10	29,000	1,625	1,239	110
South	13	7,500	2,315	1,365	107
Total	47	57,000	6,590	4,938	436


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

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



		Three Months Ended March 31,						Variance 2019 vs. 2018
		2019			2018			Increase (Decrease)			Percent
	(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	1,205		$	1,186		$	19		2	%
Transportation, processing and other		103			97			6			6	%
Trading and marketing (losses) gains, net		(20		)	3			(23		)	*
Total operating revenues		1,288			1,286			2			—	%
Purchases and related costs		(951		)	(934		)	17			2	%
Operating and maintenance expense		(165		)	(148		)	17			11	%
Depreciation and amortization expense		(93		)	(84		)	9			11	%
General and administrative expense		(6		)	(4		)	2			50	%
Other expense, net		(5		)	(3		)	2			67	%
Earnings from unconsolidated affiliates (a)		—			1			(1		)	(100	)%
Segment net income		68			114			(46		)	(40	)%
Segment net income attributable to noncontrolling interests		(1		)	(1		)	—			—	%
Segment net income attributable to partners		$	67		$	113		$	(46	)	(41	)%
Other data:
Segment gross margin (b)		$	337		$	352		$	(15	)	(4	)%
Non-cash commodity derivative mark-to-market		$	(36	)	$	14		$	(50	)	*
Natural gas wellhead (MMcf/d) (c)		4,938			4,467			471			11	%
NGL gross production (MBbls/d) (c)		436			384			52			14	%

* Percentage change is not meaningful.


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


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


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

Three Months Ended March 31, 2019 vs. Three Months Ended March 31, 2018

Total Operating Revenues — Total operating revenues increased $2 million in 2019 compared to 2018, primarily as a result of the following:


•	$164 million increase primarily as a result of increased volume from growth projects related to our DJ Basin system in the North region, increased volumes in the Permian region and increased drilling activity in our Eagle Ford system in the South region; and


•	$6 million increase in transportation, processing and other primarily related to increased volumes;

These increases were partially offset by:


•	$145 million decrease attributable to lower NGL and crude prices, partially offset by higher natural gas prices, which impacted both sales and purchases, before the impact of derivative activity; and


•	$23 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $50 million, partially offset by an increase in realized cash settlement gains of $27 million due to movements in forward prices of commodities in 2019.

Purchases and Related Costs — Purchases and related costs increased $17 million in 2019 compared to 2018 as a result of increased gas and NGL sales volumes in our North, Permian and South regions and higher natural gas prices, partially offset by lower NGL and crude prices.

Other Expense, net — Other expense in 2019 represents the write-off of property, plant and equipment.

Segment Gross Margin — Segment gross margin decreased $15 million in 2019 compared to 2018, primarily as a result of the following:


•	$23 million decrease as a result of commodity derivative activity as discussed above; and


•	$18 million decrease as a result of lower commodity prices;

These decreases were partially offset by:


•	$26 million increase primarily as a result of increased volume from growth projects related to our DJ Basin system in the North region, increased volumes in the Permian region and increased drilling activity in our Eagle Ford system in the South region;

Total Wellhead — Natural gas wellhead increased in 2019 compared to 2018 reflecting higher volumes primarily from (i) growth projects within the North region, (ii) increased drilling activity in the South region and (iii) higher volumes in the Permian and Midcontinent regions.

NGL Gross Production — NGL gross production increased in 2019 compared to 2018 primarily as a result of (i) growth projects within the North region and (ii) higher volumes in the South, Permian and Midcontinent regions.

Liquidity and Capital Resources

We expect our sources of liquidity to include:


•	cash generated from operations;


•	cash distributions from our unconsolidated affiliates;


•	borrowings under our Credit Agreement;


•	proceeds from asset rationalization;


•	debt offerings;


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


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


•	letters of credit.

We anticipate our more significant uses of resources to include:


•	quarterly distributions to our common unitholders and General Partner, and distributions to our preferred unitholders;


•	payments to service our debt;


•	growth capital expenditures;


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


•	business and asset acquisitions; and


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

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

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

Senior Notes — On January 18, 2019, we issued an additional $325 million of aggregate principal amount of our existing $500 million 5.375% Senior Notes due July 2025. We received proceeds of $324 million, net of underwriters’ fees, related expenses and issuance premiums, which we used for general partnership purposes including the funding of capital expenditures and repayment of outstanding indebtedness under the Credit Agreement. The full $825 million of our 5.375% Senior Notes due July 2025 is treated as a single series of debt. The 2025 notes will mature on July 15, 2025 unless redeemed prior to maturity. Interest on the 2025 notes is payable semi-annually in arrears on January 15 and July 15 of each year.

Credit Agreement — As of March 31, 2019, we had unused borrowing capacity of $1,307 million, net of $13 million of letters of credit, and $80 million of outstanding borrowings under the Credit Agreement. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. As of May 1, 2019, we had approximately $783 million of unused borrowing capacity under the Credit Agreement, net of $15 million of letters of credit.

Issuance of Securities — In November 2017, we filed a shelf registration statement with the SEC that became effective upon filing and allows us to issue an indeterminate amount of common units, preferred units, and debt securities. On January 18, 2019, we issued $325 million of additional aggregate principal amount to our existing $500 million 5.375% Senior Notes due July 2025 under this shelf registration statement.

In August 2017, we filed a shelf registration statement with the SEC which allows us to issue up to $750 million in common units pursuant to our at-the-market program. During the three months ended March 31, 2019, we did not issue any common units pursuant to this registration statement, and $750 million remained available for future sales.

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 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 $1,322 million and $633 million as of March 31, 2019 and December 31, 2018, respectively. The change in working capital is primarily attributable to current maturities of long-term debt. We had a net derivative working capital deficit of $26 million and surplus of $17 million as of March 31, 2019 and December 31, 2018, respectively.

As of March 31, 2019, we had $1 million in cash and cash equivalents, all of which was held by consolidated subsidiaries we do not wholly own.

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



	Three Months Ended March 31,
	2019			2018
	(millions)
Net cash provided by operating activities	$	317		$	122
Net cash used in investing activities	$	(210	)	$	(181	)
Net cash used in financing activities	$	(107	)	$	(95	)

Three Months Ended March 31, 2019 vs. Three Months Ended March 31, 2018

Operating Activities - Net cash provided by operating activities increased $195 million in 2019 compared to the same period in 2018. 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 "Results of Operations".

Investing Activities - Net cash used in investing activities increased $29 million in 2019 compared to the same period in 2018 primarily as a result of higher capital expenditures used for construction of the O'Connor 2 facility and associated gathering infrastructure, and higher investments in unconsolidated affiliates for the investment in Gulf Coast Express, capacity expansions of the Front Range, Texas Express and Sand Hills pipelines, and extension of the Southern Hills pipeline, offset by proceeds from the sale of our wholesale propane business in 2019.

Financing Activities - Net cash used in financing activities increased $12 million in 2019 compared to the same period in 2018 primarily as a result of lower net proceeds from long-term debt, partially offset by lower distributions paid to limited partners and the general partner due to $40 million of IDR givebacks paid in 2018 previously withheld in 2017 and distributions paid to preferred unitholders in 2019.

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


•	Maintenance 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. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and

•

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

The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities for the three months ended March 31, 2019 and 2018:



	Three Months Ended March 31, 2019						Three Months Ended March 31, 2018
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures			Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(millions)
Our portion	$	20	$	162	$	182	$	23		$	101	$	124
Noncontrolling interest portion and reimbursable projects (a)	—		—		—		(1		)	1		—
Total	$	20	$	162	$	182	$	22		$	102	$	124

(a)Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into agreements with third parties whereby we will be reimbursed for certain expenditures. Depending on the timing of these payments, we may be reimbursed prior to incurring the capital expenditure.

In addition, we invested cash in unconsolidated affiliates of $131 million and $60 million during the three months ended March 31, 2019 and 2018, respectively, to fund our share of capital expansion projects.

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

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

Cash Distributions to Unitholders — Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the Partnership Agreement. We made cash distributions to our common unitholders and general partner of $154 million and $194 million during the three months ended March 31, 2019 and 2018, respectively.

In accordance with our Partnership Agreement, distributions declared were $155 million for the three months ended March 31, 2019. During the three months ended March 31, 2019, no IDR giveback was withheld from the distribution declared.

On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of$0.4922 and $0.4969 per unit, respectively. The Series B distributions will be paid on June 17, 2019 to unitholders of record on June 3, 2019. The Series C distribution will be paid on July 15, 2019 to unitholders of record on July 1, 2019.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 16. "Partnership Equity and Distributions" in the Notes to the Condensed Consolidated Financial Statements in Item 1. “Financial Statements.”

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of March 31, 2019, was as follows:



	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(millions)
Debt (a)	$	8,239	$	1,195	$	955	$	1,235	$	4,854
Operating lease obligations	93		22		41		21		9
Purchase obligations (b)	4,540		955		1,222		997		1,366
Other long-term liabilities (c)	151		—		9		20		122
Total	$	13,023	$	2,172	$	2,227	$	2,273	$	6,351


(a)	Includes interest payments on debt securities that have been issued. These interest payments are $270 million, $455 million, $385 million, and $2,029 million for less than one year, one to three years, three to five years, and thereafter, respectively.

(b)

Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction agreements for capital expenditures, various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including long-term fractionation agreements. For contracts where the price paid is based on an index or other market-based rates, the amount is based on the forward market prices or current market rates as of March 31, 2019. Purchase obligations exclude accounts payable, accrued taxes and other current

liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from

the table.

(c)

Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities and other miscellaneous liabilities recognized in the March 31, 2019 condensed consolidated balance sheet. The table above excludes non-cash obligations as well as $36 million of Executive Deferred Compensation Plan contributions and $7 million of long-term incentive plans as the amount and timing of any payments are not subject to reasonable estimation.

Off-Balance Sheet Obligations

As of March 31, 2019, we had no items that were classified as off-balance sheet obligations.

Reconciliation of Non-GAAP Measures

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

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

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

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

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


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


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


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


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

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

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

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

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

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

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



		Three Months Ended March 31,
		2019			2018
Reconciliation of Non-GAAP Measures	(millions)

Reconciliation of net income attributable to partners to gross margin:

Net income attributable to partners		$	75		$	62
Interest expense		69			67
Income tax expense		1			1
Operating and maintenance expense		178			162
Depreciation and amortization expense		103			94
General and administrative expense		67			59
Other expense, net		5			2
Earnings from unconsolidated affiliates		(113		)	(78		)
Loss on sale of assets, net		9			—
Net income attributable to noncontrolling interests		1			1
Gross margin		$	395		$	370
Non-cash commodity derivative mark-to-market (a)		$	(54	)	$	(29	)

Reconciliation of segment net income attributable to partners to segment gross margin:

Logistics and Marketing segment:
Segment net income attributable to partners		$	147		$	79
Operating and maintenance expense		9			11
Depreciation and amortization expense		3			3
General and administrative expense		3			3
Other income, net		—			(1		)
Earnings from unconsolidated affiliates		(113		)	(77		)
Loss on sale of assets, net		9			—
Segment gross margin		$	58		$	18
Non-cash commodity derivative mark-to-market (a)		$	(18	)	$	(43	)

Gathering and Processing segment:
Segment net income attributable to partners		$	67		$	113
Operating and maintenance expense		165			148
Depreciation and amortization expense		93			84
General and administrative expense		6			4
Other expense, net		5			3
Earnings from unconsolidated affiliates		—			(1		)
Net income attributable to noncontrolling interests		1			1
Segment gross margin		$	337		$	352
Non-cash commodity derivative mark-to-market (a)		$	(36	)	$	14


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



	Three Months Ended March 31,
	2019		2018
	(millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:

Logistics and Marketing segment:
Segment net income attributable to partners (a)	$	147	$	79
Non-cash commodity derivative mark-to-market	18		43
Depreciation and amortization expense, net of noncontrolling interest	3		3
Distributions from unconsolidated affiliates, net of earnings	6		5
Loss on sale of assets, net	9		—
Other income	—		(1		)
Adjusted segment EBITDA	$	183	$	129

Gathering and Processing segment:
Segment net income attributable to partners	$	67	$	113
Non-cash commodity derivative mark-to-market	36		(14		)
Depreciation and amortization expense, net of noncontrolling interest	92		84
Distributions from unconsolidated affiliates, net of earnings	5		8
Other expense	5		3
Adjusted segment EBITDA	$	205	$	194


(a)	We had lower of cost or market adjustments of $5 million for the three months ended March 31, 2019. There were no lower of cost or market adjustments for the three months ended March 31, 2018.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in "Critical Accounting Policies and Estimates" within Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2018 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, 2018. With the exception of updates to significant accounting policies discussed in Note 2 of this Quarterly Report on Form 10-Q, the accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three months ended March 31, 2019 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2018. 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, 2018.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" in our Annual Report on Form 10-K for the year ended December 31, 2018.

The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering and processing operations. Our positions as of May 1, 2019 were as follows:

Commodity Swaps



Period	Commodity	Notional Volume - Short Positions	Reference Price	Price Range
April 2019 — December 2019	Natural Gas	(50,000) MMBtu/d	NYMEX Final Settlement Price (c)	$3.01-$3.28/MMBtu
April 2019 — December 2019	NGLs	(11,458) Bbls/d (d)	Mt. Belvieu (b)	$.31-$.92/Gal
April 2019 — February 2020	Crude Oil	(5,278) Bbls/d (d)	NYMEX crude oil futures (a)	$57.12-$66.29/Bbl
March 2020 — May 2020	Crude Oil	(1,057) Bbls/d (d)	NYMEX crude oil futures (a)	$61.61-$62.40/Bbl

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

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

(d) Average Bbls/d per time period.

Our sensitivities for 2019 as shown in the table below are estimated based on our average estimated commodity price exposure and commodity cash flow protection activities for the calendar year 2019, and exclude the impact of non-cash mark-to-market changes on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to mitigate a portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with our condensate, natural gas and NGL volumes that are currently unhedged.

Commodity Sensitivities Net of Cash Flow Protection Activities



	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(millions)
NGL prices	$	0.01	Gallon	$	3
Natural gas prices	$	0.10	MMBtu	$	7
Crude oil prices	$	1.00	Barrel	$	3

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

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

Non-Cash Mark-To-Market Commodity Sensitivities



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

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

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

Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long-term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. Additionally, the level of NGL export demand may also have an impact on prices. We believe that future natural gas prices will be influenced by the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and the balance of trade between imports and exports of liquid natural gas and NGLs. 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 market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

The following tables set forth additional information about our derivative instruments, used to mitigate a portion of our natural gas price risk associated with our inventory within our natural gas storage operations as of March 31, 2019:

Inventory

Period ended

Commodity

Notional Volume - Long

Positions

Fair Value

(millions)

Weighted

Average Price

March 31, 2019

Natural Gas

8,370,604

MMBtu

$2.72/MMBtu

Commodity Swaps

Period

Commodity

Notional Volume - (Short)/Long

Positions

Fair Value

(millions)

Price Range

April 2019-January 2020

Natural Gas

(16,785,000

)

MMBtu

$2.63-$3.11/MMBtu

April 2019-May 2019

Natural Gas

8,515,000

MMBtu

—

$2.69-$2.86/MMBtu

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the "Certifying Officers"), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of March 31, 2019, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of March 31, 2019, our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2019 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 19 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, 2018 and (b) Note 18 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q are incorporated herein by reference.

Item 1A. Risk Factors

In addition to the other information set forth in this report, 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, 2018. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2018. There are no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2018, except as follows:

Recently enacted laws and corresponding rulemakings in Colorado could have a material adverse impact on new oil and gas development in the state and could reduce the demand for our services in the state.

On April 16, 2019, the Colorado Governor signed into law Senate Bill 19-181 (“S.B. 181”), which amended existing laws and enacted new laws concerning the conduct of oil and gas operations in Colorado. The bill mandates the Colorado Oil and Gas Conservation Commission (the “COGCC”) to “regulate,” as opposed to the previous mandate to “foster,” the development and production of oil and gas, and requires the current nine-member COGCC to be restructured with reduced oil and gas representation to five full-time paid commissioners, only one of whom will be required to have any industry expertise. Other key elements of S.B. 181 include granting local governments ability to regulate facility siting and surface impacts of oil and gas operations and the ability to inspect and impose fines for leaks, spills, and emissions, and requiring the CDPHE to adopt additional rules that call for the minimization and continual monitoring of emissions at oil and gas facilities. S.B. 181 also requires the COGCC to conduct rulemakings concerning the cumulative impacts of oil and gas development, additional flowline regulations, as well as other matters. While much of our oil and gas infrastructure in Colorado is not located near populous areas, the population in Colorado continues to grow, which may result in populated areas coming closer to existing and proposed oil and gas development. These new laws, and regulatory rulemakings at state and local levels that may be introduced in the future, could cause a curtailment in the permitting of new oil and gas development and facilities as well as an increase in costs to us and our producer customers. Any such curtailments on new oil and gas development, would, as production from existing and previously permitted wells depletes, lead to a reduction in demand for our gathering, processing, and transportation services in the state, which reduction, over time, may be material.



Exhibit Number		Description
3.1	*	Certificate of Limited Partnership of DCP Midstream Partners, LP dated August 5, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP's Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on September 16, 2005).
3.2	*	Certificate of Amendment to Certificate of Limited Partnership of DCP Midstream Partners, LP dated January 11, 2017 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 17, 2017).
3.3	*	Fourth Amended and Restated Agreement of Limited Partnership of DCP Midstream, LP dated October 4, 2018 (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 October 4, 2018).
4.1	*	Seventh Supplemental Indenture, dated as of July 17, 2018, by and among DCP Midstream Operating, LP, DCP Midstream, LP, and The Bank of New York Mellon Trust Company, N.A. (attached as Exhibit 4.3 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 17, 2018).
4.2	*	Form of 5.375% Notes due 2025 (included in Exhibit 4.1 hereto).
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream, LP for the three months ended March 31, 2019, 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.

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	DCP Midstream, LP

	By:	DCP Midstream GP, LP its General Partner

	By:	DCP Midstream GP, LLC its General Partner

Date: May 7, 2019	By:	/s/ Wouter T. van Kempen
		Name:	Wouter T. van Kempen
		Title:	President and Chief Executive Officer
			(Principal Executive Officer)

Date: May 7, 2019	By:	/s/ Sean P. O'Brien
		Name:	Sean P. O'Brien
		Title:	Group Vice President and Chief Financial Officer
			(Principal Financial Officer)