DCP Midstream LP : Third Quarter 2020 Earnings Presentation

Third Quarter 2020 Earnings Call

Forward-Looking Statements

This presentation may contain or incorporate by reference forward-looking statements regarding DCP Midstream, LP (the "Partnership" or "DCP") and its affiliates, including outlook, guidance, projections, estimates, forecasts, plans, and objectives. All statements in this presentation, other than statements of historical fact, are forward-looking statements and are typically identified by words such as "target," "outlook," "guidance," "may," "could," "will," "should," "intend," "assume," "project," "believe," "predict," "anticipate," "expect," "scheduled," "estimate," "budget," "optionality," "potential," "plan," "forecast," and other similar words and expressions. Although management believes that expectations reflected in such forward-looking statements are based on reasonable assumptions, no assurance can be given that such expectations will prove to be correct due to risks, uncertainties, and assumptions that are difficult to predict and that may be beyond our control. If any of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership's actual results may vary materially from what management anticipated, expected, projected, estimated, forecasted, planned, or intended. You are cautioned not to place undue reliance on any forward-looking statements.

Investors are encouraged to consider closely the risks and uncertainties disclosed in the Partnership's most recent Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission, which risks and uncertainties include, but are not limited to, the ongoing global economic impacts of the COVID-19 pandemic, and pricing and supply actions by oil exporting countries, the resulting supply of, demand for, and price of oil, natural gas, NGLs, and related products and services, the duration of the foregoing impacts, and the time period for any recovery in commodity prices and demand. These risks and uncertainties could cause our actual results to differ materially from the forward-looking statements in this presentation, which may include, but are not limited to, our expectations on outlook, guidance, and sensitivities, our 2020 mitigating actions and options including distribution, capital, and cost reductions, our sources and uses of liquidity and sufficiency of financial resources, our projected in-service dates for growth projects, and our construction costs or capital expenditures in relation to estimated or budgeted amounts. Furthermore, in addition to causing our actual results to differ, such risks and uncertainties may cause our assumptions and intentions to change at any time and without notice, and any such changes may also cause our actual results to differ materially from the forward- looking statements in this presentation.

The Partnership undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Information contained in this presentation speaks only as of the date hereof unless otherwise expressed, is unaudited, and is subject to change.

Regulation G: This document includes non-GAAP financial measures as defined under the rules and regulations of the Securities and Exchange Commission, such as adjusted EBITDA, distributable cash flow, excess free cash flow, segment adjusted EBITDA, segment adjusted gross margin, forecasted adjusted EBITDA, forecasted distributable cash flow, and forecasted excess free cash flow. A reconciliation of these measures to the most directly comparable GAAP measures is included in the Appendix to this presentation.

2

Successfully Navigating the Cycle

Operational

Excellence

Maintaining top safety

performance while driving emissions reductions and improved reliability

Growing Excess

Free Cash Flow

Generated $130 million of excess free cash flow(1) in Q3; $152 million YTD

Strong Financial	Continued Cost &
Results	Capital Efficiency
Generated $331 million	Expect to beat YoY $120MM
of Adjusted EBITDA	cost reduction target;
and $232 million of	Delivering a 71% reduction
DCF in Q3	in YTD total capital

Prioritizing Debt	Leading on Innovation
Reduction	& Transformation
$156 million of debt	Recognized by World
reduction in Q3;	Economic Forum as Global
Bank leverage	Lighthouse; Launched largest
improved to 3.9x(2)	industry-led methane survey

Note: Adjusted EBITDA, distributable cash flow, and excess free cash flow are Non-GAAP financial measures
(1)	Excess Free Cash Flow = DCF less distributions to limited partners and the general partner, less distributions to noncontrolling interests, and less expansion capital expenditures and contributions to equity	3
method investments
(2)	Bank leverage ratio calculation = Bank debt (excludes $550 million Jr. Subordinated notes which are treated as equity) less cash, divided by Adjusted EBITDA, plus certain capital project EBITDA credits

Q3 2020 Financial Results

							$43		$21	$81
						$17
					$10
							$232
($MM)		( $17)	($10)	($1)
$190
										$130
	Leverage							Leverage
	4.0x							3.9x
	Q3 2019	Price Net	G&P Non-	Financing/	Sustaining	Logistics	Costs	Q3 2020	Growth	Distributions	Q3 2020
	DCF	of Hedge	Price Margin	Other	Capital	Margin		DCF	Capital/Other		Excess FCF
		Settlements

Q3 2020 Drivers (YoY)

Q3 2020 Volumes (YoY)

• Continued commitment to cost discipline, partially driven by DCP 2.0 efficiencies
• Continued capital prioritization driving low sustaining capital, while maintaining operational excellence

• Low growth capital as DCP concludes final phase of multi-year major project portfolio
• Higher Gulf Coast Express and Sand Hills earnings offsetting Guadalupe declines
• Lower commodity prices

• Increased NGL pipeline throughput driven by increased ethane recovery and short haul volumes
• Incremental volumes from Gulf Coast Express, Southern Hills extension, Front Range and Texas Express expansions, and Cheyenne Connector
• Decrease in overall G&P volumes, driven by the South and Midcon, partially offset by slight increases in high margin YoY DJ Basin and Permian wellhead volumes

4

Solid Financial Position

Increased

Excess FCF

$152MM

Enhanced

Efficiencies

17% YoY

Cost

Reduction

Lowered Improved

Debt Leverage

$175MM 3.9x

Diversified		Stable
Earnings		Cash Flows
62%		83% Fee +
Logistics		Hedged

Solid

Liquidity

~$1.3B

RA

Progress

Fitch

Improved

to Stable

Strengthening the balance sheet to ensure stability through continued uncertainty

Note: All metrics represent YTD results as of September 30, 2020 except leverage, which is calculated on a TTM basis

5

Delivering on Commitments

	Q3 Results	Q4 Outlook	2H Expectations
L&M Volumes	Q3 volumes	Expected declines due to
flat to Q2	reduced ethane recovery
G&P Volumes	Q3 volumes slightly	Slight increase
down to Q2	in volumes
Ethane	~50% increase in ethane	Maintaining partial
Rejection	recovery from Q2	recovery
Costs	Slight sequential	Increased costs due to
increase	project deferrals
Sustaining	Continued discipline driving	Increased capital due to
Capital	spend down meaningfully	project deferrals
Growth Capital	Slightly exceeded high	Minimal
end of range in Q3	capex
Prices	NGL - $0.44/gal	Stronger natural gas
Nat Gas - $1.98/MMBtu
prices; NGL and crude flat
	Crude - $40.93/Bbl

Outperformance demonstrating resiliency and durability of DCP business model

6

Long-Term Strategy Ensuring Stability

Enhance our environmental, social, and governance performance to ensure long-termsustainability and operational excellence

Maintain best in class cost and capital discipline through continued DCP 2.0 transformational efforts

Transitioned focus from capital growth to returns, and accelerate increased and sustainable excess FCF generation

Improve leverage and operate from a position of strength with financial flexibility

Create long-term value and drive increased unitholder return

7

Appendix

Financial and Other Supporting Slides

8

2020 Financial Guidance

2020 Guidance	2020 Commodity Prices
($ in Millions)	YTD	2H
	Realized	Target

Adjusted EBITDA(1)	$1,205	- $1,345
Distributable Cash Flow (DCF) (1)(2)	$730	- $830
Excess Free Cash Flow (FCF)(1)(3)	$129	- $269
Bank Leverage(4)	~4.0x

NGL ($/gallon)	$0.38	$0.41
Natural Gas ($/MMBtu)	$1.88	$1.95
Crude Oil ($/Bbl)	$38.32	$40.00

2020e Sensitivities(5)

Commodity	Per unit ∆	Before Hedges	Hedge Impact	After Hedges
($MM)	($MM)	($MM)
NGL ($/gallon)	$0.01	$5	($2)	$3
Natural Gas ($/MMBtu)	$0.10	$8	($2)	$6
Crude Oil ($/Bbl)	$1.00	$4	($2)	$2

Note: 2020 financial guidance consists of forecasted Adjusted EBITDA and DCF ranges originally announced on February 11, 2020 and reissued on August 6, 2020 with the addition of an excess free cash flow guidance range

1. Adjusted EBITDA, distributable cash flow, and excess free cash flow are Non-GAAP financial measures

(2)	Distributable cash flow is reduced by cumulative cash distributions earned by the Preferred Units	9
(3)	Excess Free Cash Flow = DCF less distributions to limited partners and the general partner, less distributions to noncontrolling interests, and less expansion capital expenditures and contributions to equity method investments.
(4)	Bank leverage ratio calculation = Bank debt (excludes $550 million Jr. Subordinated notes which are treated as equity) less cash divided by Adjusted EBITDA, plus certain capital project EBITDA credits
(5)	Sensitivities are relevant to margin impacts

Q2 2020 vs. Q3 2020 Financial Results

Improved commodity prices more than offsetting increased

financing and costs

Distributable Cash Flow

		($MM)
		$2	$3	$17
($5)	($4)	($1)
				$232
$220

Q2 2020 DCF	Financing	Costs	Sustaining	Logistics	G&P Non-Price	Price Net of Hedge	Q3 2020
	/ Tax		capital	margin	Margin	Settlements	DCF

10

Adjusted EBITDA by Segment

Logistics & Marketing Adjusted EBITDA*

										($MM)	$42
															$1
		$200				($26)	($1)										$216

Q3 2019	Gas and NGL	Other	Costs	NGL and Gas	Q3 2020
Adjusted EBITDA	Marketing			Pipelines	Adjusted EBITDA

Gathering & Processing Adjusted EBITDA*

($MM)

* Adjusted Segment EBITDA is viewed as a non-Generally Accepted Accounting Principles (GAAP) financial measure under the rules of the SEC and is reconciled to its most	11
directly comparable GAAP financial measure under "Reconciliation of Non-GAAP Financial Measures" in schedules at the end of this presentation

Volumes by Segment

NGL Pipeline Volume Trends and Utilization

					Q3'19	Q2'20	Q3'20	Q3'20
			Average		Average NGL	Average NGL	Average NGL
			Gross
NGL Pipeline		Approx System	Capacity	Net Capacity	Throughput	Throughput	Throughput	Pipeline
% Owned	Length (Miles)	(MBbls/d)	(MBpd)	(MBpd)(1)	(MBpd)(1)	(MBpd)(1)	Utilization
Sand Hills	66.7%	1,410	500	333	321	312	307	92%
Southern Hills	66.7%	950	192	128	86	100	104	81%
Front Range	33.3%	450	260	87	45	56	57	66%
Texas Express	10.0%	600	370	37	17	19	20	54%
Other(2)	Various	1,110	395	310	129	189	192	62%
Total		4,520	1,717	895	598	676	680

Q3 2020 Southern Hills volumes up 21% vs. Q3 2019

Q3 2020 Front

Range volumes up

27% vs. Q3 2019

G&P Volume Trends and Utilization						Q3 2020 SE New
	Q3'20	Q3'19	Q2'20	Q3'20	Q3'20	Q3'20		Mexico volumes
	Net Plant/	Average	Average	Average
				~9% higher than
	Treater	Wellhead	Wellhead	Wellhead	Average NGL	Plant
System	Capacity	Volumes	Volumes	Volumes	Production		Q3 2019
(MMcf/d)	(MMcf/d) (5)	(MMcf/d) (5)	(MMcf/d) (5)	(MBpd)	Utilization(3)
North(4)	1,580	1,488	1,531	1,506	126	95%
Permian	1,200	957	987	975	119	81%		Q3 2020 DJ Basin
Midcontinent	1,110	1,106	842	834	71	75%
	wellhead volumes
South	2,120	1,406	1,127	1,049	90	49%
Total	6,010	4,957	4,487	4,364	406	73%		~5% higher than
								Q3 2019.
(1) Represents total throughput allocated to our proportionate ownership share
(2)	Other includes Wattenberg, Black Lake, Panola, Seabreeze, Wilbreeze, and other NGL pipelines				12
(3) Plant utilization: Average wellhead volumes divided by active plant capacity, excludes idled plant capacity
(4) Q3'19, Q2'20 and Q3'20 include 1,183 MMcf/d, 1,252 MMcf/d and 1,239 MMcf/d, respectively, of DJ Basin wellhead volumes. Remaining volumes are Michigan and Collbran
(5)	Average wellhead volumes may include bypass and offload

Margin by Segment*

MARGIN/EQUITY EARNINGS BY SEGMENT **
$MM, except per unit measures		Q3 2020		Q2 2020		Q1 2020		Q4 2019		Q3 2019
Gathering & Processing (G&P) Segment
	Natural gas wellhead - Bcf/d		4.36		4.49		4.94		5.00		4.96
	Segment adjusted gross margin including equity earnings before hedging (1)	$	304	$	264	$	299	$	333	$	317
	Non-cash impairment in equity investment	$	-	$	-	$	(61)	$	-	$	-
	Net realized cash hedge settlements received (paid)	$	13	$	29	$	9	$	20	$	19
	Non-cash unrealized gains (losses)	$	(39)	$	(62)	$	92	$	(23)	$	(5)
	G&P Segment adjusted gross margin including equity earnings	$	278	$	231	$	339	$	330	$	331
	G&P adjusted margin including equity earnings before hedging/wellhead mcf	$	0.76	$	0.65	$	0.66	$	0.73	$	0.69
	G&P adjusted margin including equity earnings and realized hedges/wellhead mcf	$	0.79	$	0.72	$	0.68	$	0.77	$	0.74
Logistics & Marketing Segment adjusted gross margin incl equity earnings (2)	$	220	$	194	$	248	$	175	$	174
	Total adjusted gross margin including equity earnings	$	498	$	425	$	587	$	505	$	505
	Direct Operating and G&A Expense	$	(212)	$	(208)	$	(209)	$	(255)	$	(255)
	DD&A		(92)		(93)		(99)		(100)		(100)
	Other Income (Loss) (3)		(4)		(5)		(749)		(68)		(247)
	Interest Expense, net		(77)		(71)		(78)		(83)		(79)
	Income Tax Benefit (Expense)		(1)		0		(1)		3		(1)
	Noncontrolling interest		(1)		(1)		(1)		(1)		(1)
	Net Income (Loss) - DCP Midstream, LP	$	111	$	47	$	(550)	$	1	$	(178)
	Industry average NGL $/gallon	$	0.44	$	0.32	$	0.39	$	0.50	$	0.44
	NYMEX Henry Hub $/MMBtu	$	1.98	$	1.72	$	1.95	$	2.50	$	2.23
	NYMEX Crude $/Bbl	$	40.93	$	27.85	$	46.17	$	56.91	$	56.45
	Other data:
	NGL pipelines throughput (MBbl/d) (4)		680		676		677		599		598
	NGL production (MBbl/d)		406		376		404		404		406

*Segment adjusted gross margin is viewed as a non-Generally Accepted Accounting Principles ("GAAP") measure under the rules of the Securities and Exchange Commission ("SEC"), and is reconciled to its most directly comparable GAAP financial measures under "Reconciliation of Non-GAAP Financial Measures" in schedules at the end of this presentation.

1. Represents Gathering and Processing (G&P) Segment adjusted gross margin plus Earnings from unconsolidated affiliates, excluding trading and marketing (losses) gains, net, before non-cash impairment in equity investment
2. Represents Logistics and Marketing Segment adjusted gross margin plus Earnings from unconsolidated affiliates
3. "Other Income" includes asset impairments in Q1 2020 and Q3 2019, goodwill impairment in Q1 2020 and Q3 2019, gain/(loss) on asset sales and other miscellaneous items
4. This volume represents equity and third party volumes transported on DCP's NGL pipeline assets

13

Disciplined and Strategic Capital Projects

Projects in Progress or Recently In-Service	Est. 100%	Total Est.	Expected
($MM net to DCP's interest for JVs)	Capacity	CapEx ($MM)	In-Service
Gathering & Processing
Latham 2 Offload
• Long-term gas processing offload agreement at Western Midstream Partners	225 MMcf/d	$125	Q4 2020
Latham facility, with retention of full downstream NGL and gas upside

• Brings DCP's total processing, bypass, and offload capacity to over 1.6 Bcf/d in the DJ Basin

Final stage of multi-year strategic growth program; minimal 2021 capex expected

14

Hedge Position

As of October 31, 2020

CommodityQ1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Avg. 2021 Avg.

NGLs hedged (Bbls/d)	10,352	10,352	13,011	13,011	11,681	4,570
Targeted average hedge price(1) ($/gal)	$0.48	$0.48	$0.48	$0.48	$0.48	$0.46
% NGL exposure hedged					35%
Gas hedged (MMBtu/d)	35,000	5,000	5,000	172,500	54,375	160,000
Average hedge price ($/MMBtu)	$2.66	$2.58	$2.58	$2.85	$2.81	$2.51
% gas exposure hedged					25%
Crude hedged (Bbls/d)	8,813	8,022	4,978	3,978	6,448	2,491
Average hedge price ($/Bbl)	$58.12	$57.88	$57.60	$57.03	$57.77	$54.07
% crude exposure hedged					66%

Total Equity Length Hedged(2)

2020 2021

43% 33%

2022

10%

Multi-year hedge program providing increased stability within cash flows

(1)	Targeted average hedge price is inclusive of existing propane and normal butane hedges at average hedge prices of $0.52 and $0.60 respectively, as well as targets for	15
(2)	additional purity products
Based on crude equivalent

Non-GAAP Reconciliations

16

Non-GAAP Reconciliations

• 1. Non-cashcommodity derivative mark-to-market is included in adjusted gross margin and segment adjusted gross margin, along with cash settlements for our commodity derivative contracts.
• We define adjusted gross margin as total operating revenues, less purchases and related costs, and we define segment adjusted gross margin for each segment as total operating revenues for that segment less purchases and related costs for that segment. Our adjusted gross margin equals the sum of our segment adjusted gross margins. Adjusted gross margin and segment

adjusted gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations.	17
As an indicator of our operating performance, adjusted gross margin and segment adjusted gross margin should not be considered an alternative to, or more meaningful than, operating

revenues, gross margin, segment gross margin, net income or loss, net income or loss attributable to partners, operating income, net cash provided by operating activities or any other measure

of financial performance presented in accordance with GAAP.	17

Non-GAAP Reconciliations

18

18

Non-GAAP Reconciliations

19

19

Non-GAAP Reconciliations

20