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.
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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
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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 - $40.93/Bbl | ||||
Outperformance demonstrating resiliency and durability of DCP business model
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Long-Term Strategy Ensuring Stability
Enhance our environmental, social, and governance performance to ensure long-termsustainability and operational excellence
Maintain best in class cost and capital discipline through continued DCP 2.0 transformational efforts
Transitioned focus from capital growth to returns, and accelerate increased and sustainable excess FCF generation
Improve leverage and operate from a position of strength with financial flexibility
Create long-term value and drive increased unitholder return
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Appendix
Financial and Other Supporting Slides
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2020 Financial Guidance
2020 Guidance | 2020 Commodity Prices | |
($ 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
- 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 | ||||
$220 |
Q2 2020 DCF | Financing | Costs | Sustaining | Logistics | G&P Non-Price | Price Net of Hedge | Q3 2020 |
/ Tax | capital | margin | Margin | Settlements | DCF |
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Adjusted EBITDA by Segment
Logistics & Marketing Adjusted EBITDA*
($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.
- 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
- Represents Logistics and Marketing Segment adjusted gross margin plus Earnings from unconsolidated affiliates
- "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
- This volume represents equity and third party volumes transported on DCP's NGL pipeline assets
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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 | $125 | Q4 2020 |
Latham facility, with retention of full downstream NGL and gas upside |
- Brings DCP's total processing, bypass, and offload capacity to over 1.6 Bcf/d in the DJ Basin
Final stage of multi-year strategic growth program; minimal 2021 capex expected
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Hedge Position
As of October 31, 2020
CommodityQ1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Avg. 2021 Avg.
NGLs hedged (Bbls/d) | 10,352 | 10,352 | 13,011 | 13,011 | 11,681 | 4,570 |
Targeted average hedge price(1) ($/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
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Non-GAAP Reconciliations
- 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
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Non-GAAP Reconciliations
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Non-GAAP Reconciliations
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DCP Midstream LP published this content on 05 November 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 05 November 2020 18:36:01 UTC