DCP Midstream LP : Second Quarter 2020 Earnings Presentation

Second 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 the recent pricing and supply actions by certain 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.

2

Q2 2020 Highlights and Execution

3

Strong Execution Through The Cycle

Q2 2020 Results

Strong Financial

Performance

Volumes Favorable to

Expectations

• Strongest 1H Adjusted EBITDA and DCF in DCP company history(1), with $311 million of Q2 Adjusted EBITDA, $632 million 1H; $220 million of Q2 DCF, $440 million 1H
• Bank facility leverage lowered to 4.0x; FCF positive in Q2, significantly FCF positive in 2H
• Reissued original 2020 Adjusted EBITDA and DCF guidance ranges
• Continued strong L&M earnings, comprising ~65% of Q2 EBITDA, with uplift from ethane recovery
• YoY wellhead volumes from the DJ and Permian basins up 15% and 5%, respectively, producing higher quality earnings, partially offsetting lower overall G&P volumes
• Vast majority of producer shut-ins are back online, benefiting both segments

Key Highlights

Liquidity Secured

Strategic Execution

DJ Basin Unleashed

• Upsized senior notes issuance in June; $500 million at 5.625% due 2027
• Ample liquidity with $1.1B available; expected to increase throughout year and into 2021
• Primary financial focus is substantial delevering
• Supply long, capacity short strategy optimizes asset utilization
• DCP 2.0 capabilities fueling strategic capital management and lowest quarterly costs in history
• Leveraging integrated portfolio to proactively retain volumes on DCP systems
• Improved company risk profile with new 100% take-or-pay logistics assets
• Cheyenne Connector in-service June 2020, eliminating DJ Basin midstream constraints
• CO Gov. Polis announced a broad coalition committed to actively preventing future anti-oil and gas ballot initiatives and significant legislation through 2022
• Latham 2 offload moved to Q4; MVC effective January 1, 2021

(1) Since the company was combined with DCP Midstream, LLC	4

Deliberate Action & Resiliency

			Effective
			COVID-19
			response
			ensured
	YoY 1H	health of
Price Impact	workforce
and
			maintained
			safe and
	($125)		reliable
		operations

2020 DCF Performance	Best 1H in
DCP History
($MM)

Strategic Execution & Self-Help

Fully	Vigorous	Early action	Investment in
DCP 2.0
integrated
cost	on capital	enabled real-	$440
portfolio
discipline on	reductions,	time system
buoyed
contract	including	and margin
earnings and
services,	~$400MM	optimization,
allowed for
consumables,	growth capital	while
optimized
labor, and	reduction and	providing
producer
utilities	$23MM YoY	speed to cost
netbacks to
resulting in	sustaining	and capital
keep volumes
$87MM YoY	capital	reductions
on DCP's
improvement	reduction	and ensuring
system
		reliability

Successfully mitigating impacts of COVID-19 through multi-year company transformation,

immediate self-help, and the strong earnings power of our integrated asset base

5

Consolidated Q2 2020 Financial Results

Strong self-help performance and Logistics margins more than offsetting

unfavorable commodity prices and volume declines

Distributable Cash Flow(1)

$51

($MM)

$1

$13

$30

$220

$173

($39)

($9)

Px before hedge

$

(55)

Hedge

16

Px net of hedge

$

(39)

Q2 2019

Price Net

G&P Non-Price

Financing/

Sustaining

Logistics

Costs

Q2 2020

DCF

of Hedge

Margin

Other

Capital

Margin

DCF

Settlements

Q2 2020 Drivers (YoY)

• Best-in-classsustaining capital and cost discipline, driving increased free cash flow
• Strong Logistics margin driven by Gulf Coast Express, NGL marketing, Sand Hills, the Front Range and Texas Express expansions, and ethane recovery, partially offset by lower Guadalupe earnings

• Non-recurringreduction in force expense, driving long-term efficiencies
• Lower commodity prices, partially offset by strategic hedges
• Lower G&P margin due to Midcontinent and South volume declines, partially offset by increased DJ Basin and Permian volumes
• Costs included a one-time $9 million severance expense in Q2

(1) Q2 2019 DCF includes approximately $9MM of voluntary separation program costs. Q2 2020 DCF includes approximately $9MM of reduction in force severance costs.	6

2020 Financial Guidance Reissued

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

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

NGL ($/gallon)	$0.36	$0.41
Natural Gas ($/MMBtu)	$1.83	$1.95
Crude Oil ($/Bbl)	$37.01	$40.00

2020e Revised 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	($1)	$7
Crude Oil ($/Bbl)	$1.00	$4	($2)	$2

Targeting middle of DCF range, driven by strong focus on cash generation;

expecting low end of EBITDA range due to ongoing COVID-19 crisis

Note: Reissued 2020 financial guidance consists of forecasted Adjusted EBITDA and DCF ranges originally announced on February 11, 2020

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

(2)	Distributable cash flow is reduced by cumulative cash distributions earned by the Preferred Units	7
(3)	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

2H Assumptions and Outlook

Logistics & Marketing

• Relatively flat NGL volumes through Q3, with potential declines in Q4, due to a forecasted increase in ethane rejection
• Incremental earnings from newly in-service Cheyenne Connector beginning Q3

Gathering & Processing

• 2H G&P volumes expected to be slightly higher than Q2
• All shut in volumes back online during Q3, partially offsetting natural declines
• Latham 2 offload online in Q4

Costs & Capital(1)

• Committed to a minimum of $120 million YoY cost reduction, with costs back-loaded to 2H
• Sustaining capital heavily back-loaded to 2H; expected to exceed May outlook of ~$60 million
• Growth capital expected to be significantly lower; trending toward high end of $150 - $190 million range

Potential 2H Tailwinds

• Potential upside from continued ethane recovery
• Permian and DJ Basin DUC inventory of 3,000+ and 700+ respectively, mitigating natural declines
• Incremental rigs if commodity pricing strengthens

Potential 2H Headwinds

• Continuation of lower demand as a result of COVID-19 pandemic
• Sustained lower commodity prices
• Producer capex declines create natural production declines
• Political and regulatory risk

Strong 1H foundation balancing continued uncertainty in 2H industry outlook

(1) Compared to 1H

8

Solid Financial Position

2020 Adjusted Gross Margin

Liquidity

~$1.1B

Leverage(2)

4.0x

Free Cash Flow

Positive

Ample Liquidity

• $1.75B capacity via bank facility and A/R securitization facility; ~$650MM utilized(1)
• Issued $500 million of senior notes in Q2; proceeds used to pay down bank facility

Improved Leverage

• Reduced leverage to achieve 4.0x target
• Delevering is top financial priority
• Ba2/BB+/BB+ credit ratings
• No common equity issued since 2015

Increased FCF

• Premier assets, self-help measures, and DCP 2.0 driving sustainable FCF optimization
• $54 million of FCF in Q2 2020, fully funding distribution and all capital
• 2H significantly free cash flow positive, enhancing liquidity and delevering

	19%
	Unhedged
11%	81%(3)
Hedged	Fee-based &

hedged

Exceeded Goal	70%
of 80% Fee
Fee-based
and Hedged

2020 Free Cash Flow

($ in Millions)

Substantial free cash flow to delever

$406

$150-$190

Growth Capital

Distributions

2020 DCF

Free cash flow generation utilized for substantial delevering

(1)	As of June 30, 2020	9
(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 project EBITDA credits

1. 70% fee plus 30% commodity margin x 36% hedged = 81% fee and hedged as of July 31, 2020

Unleashing the DJ Basin

									Regulatory Stability
						DJ Basin Assets			• No ballot initiatives in 2020 Colorado election cycle,
								providing increased regulatory certainty
					Asset type				• Colorado Governor Polis announced a broad coalition
					Fractionator & Plant
								actively preventing anti-industry ballot initiatives or
					Natural Gas Plant
					Pipeline		In-Service		significant legislation through 2022
								Capital Projects
									• Cheyenne Connector in-service late Q2, eliminating
									all logistics constraints in the DJ Basin
									• Front Range and Texas Express expansions in-
									service April 1, 2020
									• Latham 2 offload in-service date moved to Q4
									o Commercial contracts begin January 2021
									o Anticipate meeting all MVC commitments
									Q2 North Business Unit Stats(1)
									Avg. Wellhead Volumes (MMcf/d)		1,531
									Utilization		97%
									Avg. NGL Production (MBpd)		122

DJ Basin unlocked by increased regulatory certainty and comprehensive infrastructure completion

(1) North Business Unit stats include the Michigan/Collbran systems	10

Differentiating DCP Midstream

Harnessing the earnings power of our assets and optimizing benefits from

DCP transformation and early downturn mitigation efforts

Supply Long, Capacity Short Capital Allocation

Disciplined capital allocation strategy of just-in-time capacity ensuring high utilization rates; increased capital efficiency by utilizing existing infrastructure; no capital projects currently slated for 2021, system adequate to meet producer supply

DCP 2.0 Transformation Fueling Response

Prior investments in digital transformation driving cost savings and real-time decision making within the ICC to manage volumetric changes, optimize margins, and improve reliability

.

Strong Financial

Performance and Position

Delivered strongest 1H Adjusted EBITDA and DCF and lowest quarterly costs in DCP history during economic and industry crisis; generating significantly positive FCF to self-fund all capital needs and delever, while providing an attractive yield to unitholders

Fully-Integrated

Service Provider

Leveraging integrated value chain to proactively keep volumes on our system; ~65% of Q2 EBITDA from L&M underpinning balanced portfolio

Continued Focus

on Operational Excellence

Pandemic response plan and continued dedication to sustainability strategy protects our employees, ensures our business continuity and reliability, and improves our

environmental footprint

11

Appendix

Financial and Other Supporting Slides

12

Q1 2020 vs. Q2 2020 Financial Results

Volume declines and non-recurring severance payments offset

by favorable costs and L&M earnings

Distributable Cash Flow

				($MM)
							$8	$10
						$6
				$4	$6
	($22)	($9)	($3)
$220									$220
Q1 '20 Actual	G&P Non-	Severance	Other	Sustaining	Price, net of	Financing	Logistics	Costs, excl	Q2 '20
DCF	Price Margin			capital	hedge	/ Tax	margin	severance	Actual
									DCF

13

Adjusted EBITDA by Segment

Logistics & Marketing Adjusted EBITDA*

										($MM)	$36
														$2
		$181	($5)	($1)												$213

Q2 2019	Gas and NGL	Other Margin	Costs	NGL and Gas	Q2 2020
Adjusted EBITDA	Marketing			Pipelines	Adjusted EBITDA

			Gathering & Processing Adjusted EBITDA*
										($MM)
							$33
		$173
		($39)												$158
		($9)

Q2 2019	Price Net	Margin/	Costs	Q2 2020
Adjusted EBITDA	of Hedge	Volumes		Adjusted EBITDA
	Settlements

* 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	14
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

						Q2'19	Q1'20	Q2'20	Q2'20
				Average		Average NGL	Average NGL	Average NGL
				Gross
					Throughput	Throughput	Throughput
			Approx System	Capacity	Net Capacity	Pipeline
NGL Pipeline	% Owned	Length (Miles)	(MBbls/d)	(MBpd)	(MBpd)	(1)	(MBpd)	(1)	(MBpd)	(1)	Utilization
Sand Hills	66.7%	1,400	500	333		324		322		312	94%
Southern Hills	66.7%	950	192	128		113		93		100	78%
Front Range	33.3%	450	260	87		49		60		56	65%
Texas Express	10.0%	600	370	37		19		20		19	51%
Other	(2)	Various	1,110	485	400		132		182		189	47%
Total			4,510	1,807	985		637		677		676

Q2 2020 Southern Hills volumes up 8% vs. Q1 2020

Q2 2020 Front

Range volumes up

14% vs. Q2 2019

G&P Volume Trends and Utilization

	Q2'20	Q2'19	Q1'20	Q2'20	Q2'20	Q2'20
	Net Plant/				Average NGL	Plant
	Treater Capacity	Average Wellhead	Average Wellhead	Average Wellhead	Production
System	(MMcf/d)	Volumes (MMcf/d) (5)	Volumes (MMcf/d) (5)	Volumes (MMcf/d) (5)	(MBpd)	Utilization(3)
North(4)	1,580	1,400	1,603	1,531	122	97%
Permian	1,200	941	1,038	987	106	82%
Midcontinent	1,110	1,140	960	842	64	76%
South	2,120	1,385	1,339	1,127	84	53%
Total	6,010	4,866	4,940	4,487	376	75%

1. Represents total throughput allocated to our proportionate ownership share
2. Other includes Wattenberg, Black Lake, Panola, Seabreeze, Wilbreeze, and other NGL pipelines
3. Average wellhead volumes may include bypass and offload
4. Plant utilization: Average wellhead volumes divided by active plant capacity, excludes idled plant capacity
5. Q2'19, Q1'20 and Q2'20 include 1,085 MMcf/d, 1,323 MMcf/d and 1,252 MMcf/d, respectively, of DJ Basin wellhead volumes. Remaining volumes are Michigan and Collbran

Q2 2020 DJ Basin wellhead volumes 15% higher than Q2 2019.

Q2 2020 SE New Mexico volumes 27% higher than Q2 2019

15

2020 and 2021 Hedges

Hedge Position as of July 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	4,241
Targeted average hedge price(1) ($/gal)	$0.48	$0.48	$0.48	$0.48	$0.48	$0.46
% NGL exposure hedged					~35%
Gas hedged (MMBtu/d)	35,000	5,000	5,000	5,000	12,500	115,000
Average hedge price ($/MMBtu)	$2.66	$2.58	$2.58	$2.58	$2.64	$2.37
% gas exposure hedged					~6%
Crude hedged (Bbls/d)	8,813	8,022	4,978	3,978	6,448	2,491
Average hedge price ($/Bbl)	$58.12	$57.88	$57.60	$57.03	$57.77	$54.07
% crude exposure hedged					~66%

Total Equity Length Hedged(2)

2020 2021

36% 27%

2022

6%

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	16
	additional purity products
(2)	Based on crude equivalent

Margin by Segment*

$MM, except per unit measures	Q2 2020	Q1 2020	Q4 2019	Q3 2019	Q2 2019
Gathering & Processing (G&P) Segment

Natural gas wellhead - Bcf/d

Segment gross margin including equity earnings before hedging (1) Non-cash impairment in equity investment

Net realized cash hedge settlements received (paid) Non-cash unrealized gains (losses)

G&P Segment gross margin including equity earnings

G&P Margin including equity earnings before hedging/wellhead mcf G&P Margin including equity earnings and realized hedges/wellhead mcf

Logistics & Marketing Segment gross margin including equity earnings (2)

Total gross margin including equity earnings

Direct Operating and G&A Expense

DD&A

Other Income (Loss) (3)

Interest Expense, net

Income Tax Benefit (Expense)

Noncontrolling interest

Net Income (Loss) - DCP Midstream, LP

	4.49		4.94		5.00		4.96		4.87
$	264	$	299	$	333	$	317	$	329
$	-	$	(61)	$	-	$	-	$	-
$	29	$	9	$	20	$	19	$	13
$	(62)	$	92	$	(23)	$	(5)	$	15
$	231	$	339	$	330	$	331	$	357
$	0.65	$	0.66	$	0.73	$	0.69	$	0.75
$	0.72	$	0.68	$	0.77	$	0.74	$	0.78
$	194	$	248	$	175	$	174	$	202
$	425	$	587	$	505	$	505	$	559
$	(208)	$	(209)	$	(255)	$	(255)	$	(259)
	(93)		(99)		(100)		(100)		(101)
	(5)		(749)		(68)		(247)		(6)
	(71)		(78)		(83)		(79)		(73)
	0		(1)		3		(1)		(0)
	(1)		(1)		(1)		(1)		(1)
$	47	$	(550)	$	1	$	(178)	$	119

Industry average NGL $/gallon	$	0.32	$	0.39	$	0.50	$	0.44	$	0.51
NYMEX Henry Hub $/MMBtu	$	1.72	$	1.95	$	2.50	$	2.23	$	2.64
NYMEX Crude $/Bbl	$	27.85	$	46.17	$	56.91	$	56.45	$	59.81
Other data:
NGL pipelines throughput (MBbl/d) (4)		676		677		599		598		637
NGL production (MBbl/d)		376		404		404		406		422

*Segment 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 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 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

17

Disciplined and Strategic Growth

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-termgas processing offload agreement at Western Midstream Partners

Latham facility, with retention of full downstream NGL and gas upside

225 MMcf/d

$125

Q4 2020

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

Logistics

Cheyenne Connector (50%)			In-Service
•	Residue gas takeaway from the DJ Basin to the Rockies Express Pipeline	600 MMcf/d	$155
•	DCP has secured 300 MMcf/d of transport	Q2 2020

• Pipeline is fully subscribed and 100% take or pay

Executing strategic projects at 5-7x target multiples in the DJ Basin where favorable life

of lease acreage dedications support downstream investments

18

Non-GAAP Reconciliations

19

Non-GAAP Reconciliations

		Three Months Ended		Year to Date Ended
		June 30,			June 30,
($ in millions)		2020		2019		2020		2019
Logistics and Marketing Segment
Segment net income attributable to partners	$	177	$	185	$	413	$	332
Operating and maintenance expense		9		11		16		20
Depreciation and amortization expense		3		3		6		6
General and administrative expense		1		1		3		4
Other expense, net		4		1		4		1
Earnings from unconsolidated affiliates		(125)		(114)		(262)		(227)
Loss on sales of assets, net		-		1		-		10
Segment gross margin	$	69	$	88	$	180	$	146
Earnings from unconsolidated affiliates		125		114		262		227
Segment gross margin including equity earnings	$	194	$	202	$	442	$	373
Gathering and Processing (G&P) Segment
Segment net income (loss) attributable to partners	$	11	$	90	$	(634)	$	157
Operating and maintenance expense		134		165		276		330
Depreciation and amortization expense		82		91		171		184
General and administrative expense		4		6		7		12
Asset impairments		-		-		746		-
Other (income) expense, net		(1)		-		2		5
(Earnings) loss from unconsolidated affiliates		-		(3)		61		(3)
Loss on sale of assets, net		-		4		-		4
Net income attributable to noncontrolling interests		1		1		2		2
Segment gross margin	$	231	$	354	$	631	$	691
(Earnings) loss from unconsolidated affiliates		-		3		(61)		3
Segment gross margin including equity earnings	$	231	$	357	$	570	$	694

• We define gross margin as total operating revenues including trading and marketing gains and losses, less purchases and related costs, and we define segment gross margin for each
  segment as total operating revenues for that segment including trading and marketing gains and losses less purchases and related costs for that segment. Segment gross margin 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 and related costs. As an indicator of our operating performance, 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.

20

20

Non-GAAP Reconciliations

21

21

Non-GAAP Reconciliations

22

22

Non-GAAP Reconciliations

23