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.
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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
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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
- 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 |
- 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
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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 | $220 | ||||||||
Q1 '20 Actual | G&P Non- | Severance | Other | Sustaining | Price, net of | Financing | Logistics | Costs, excl | Q2 '20 |
DCF | Price Margin | capital | hedge | / Tax | margin | severance | Actual | ||
DCF |
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Adjusted EBITDA by Segment
Logistics & Marketing Adjusted EBITDA*
($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% |
- Represents total throughput allocated to our proportionate ownership share
- Other includes Wattenberg, Black Lake, Panola, Seabreeze, Wilbreeze, and other NGL pipelines
- Average wellhead volumes may include bypass and offload
- Plant utilization: Average wellhead volumes divided by active plant capacity, excludes idled plant capacity
- 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
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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.
- 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
- Represents Logistics and Marketing Segment 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 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 |
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Non-GAAP Reconciliations
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Non-GAAP Reconciliations
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Non-GAAP Reconciliations
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Disclaimer
DCP Midstream LP published this content on 06 August 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 06 August 2020 16:33:02 UTC