Investor Highlights // DECEMBER 2019 Enable Midstream Overview - - PDF document
Investor Highlights // DECEMBER 2019 Enable Midstream Overview - - PDF document
Investor Highlights // DECEMBER 2019 Enable Midstream Overview Large-scale, fully-integrated midstream platform Critical link between growing production and downstream markets Long-term relationships with large-cap producers, LDCs
- Large-scale, fully-integrated
midstream platform
- Critical link between growing
production and downstream markets
- Long-term relationships with large-cap
producers, LDCs and electric utilities
- Signifjcant fee-based and
demand-fee margin
- Substantial distribution coverage
- Investment-grade credit metrics
- Proven track record
- Compelling value opportunity
13,900 Miles
Gathering Pipelines
10,100 Miles
Interstate/Intrastate Pipelines
84.5 Bcf
Natural Gas Storage Capacity
2.6 Bcf/d
Processing Capacity
31 Active Rigs
On Enable’s Footprint1
Enable Midstream Overview
Note: Map as of Nov. 7, 2019; Stats as of Dec. 31, 2018; Pipeline miles are approximate and interstate/intrastate pipeline miles include ~7,800 miles of interstate pipeline (including SESH, which Enable owns a 50% interest) and ~2,300 miles of intrastate pipeline
1Rigs drilling wells expected to be connected to Enable’s gathering systems; per Enverus as of Oct. 28, 2019
2 | Investor Highlights 1
Gathering and Processing
Rig Activity Updates
- Producers remain active around Enable’s gathering footprint
with 31 rigs1 currently drilling wells expected to be connected to Enable’s gathering systems
- 44% of all active rigs1 in the SCOOP and STACK plays are
drilling wells expected to be connected to Enable’s gathering systems
- Enable expects to gather crude oil and condensate from wells
drilled by 88% of the active rigs1 on Enable’s footprint in the SCOOP play
Q3-19 Segment Highlights
Anadarko:
- Strong well results in the STACK and SCOOP expected to
increase Q4-19 natural gas gathered volumes
- September volumes were 4% higher than Q3-19 average,
driven by a large number of new wells coming online
- Multi-well pads in the STACK recently came online,
achieving total volumes in September of over 90 MMcf/d
- Multi-well pads in the SCOOP recently came online,
achieving total volumes in October of over 180 MMcf/d
- Increased crude oil and condensate gathered volumes
during 2019
- September volumes were 12% higher than Q3-19 average,
continuing the growth trend since acquisition Ark-La-Tex:
- Haynesville contracts with MVC support expiring Q3-19 were
at a combined nearly 90% of MVC threshold levels over the last contract year and have at least fjve years of continuing acreage dedications beyond the term of the MVCs Williston:
- Record quarterly crude oil gathered volumes2
Note: SCOOP counties are designated as Caddo, Carter, Garvin, Grady, McClain and Stephens and STACK counties are designated as Blaine, Canadian, Custer, Dewey, Kingfisher, Major and Woodward counties of Oklahoma
1Rigs per Enverus as of Oct. 28, 2019; represents wells expected to be connected to
either Enable’s natural gas gathering or crude oil and condensate gathering systems
2Since Enable’s formation in May 2013 3Operational data as of Dec. 31, 2018
STACK SCOOP Granite Wash Ark-La-Tex Williston
Active Rigs on Enable’s Footprint1
31
ANADARKO ARKOMA ARK-LA-TEX WILLISTON
Natural Gas
We have natural gas gathering and processing operations in the SCOOP, STACK, Granite Wash, Cleveland, Marmaton, Tonkawa, Cana Woodford and Mississippi Lime plays. Enable serves over 200 producers3 in the Anadarko Basin and has secured 5.4 million gross acres3 of dedication under long-term, fee-based contracts.
Crude Oil and Condensate
Our operations in the Anadarko Basin include gathering of crude oil and condensate from producers in the SCOOP, STACK and Merge plays. Enable’s footprint is uniquely positioned to serve the increased drilling activity in the SCOOP play. Our operations primarily serve the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas. Our Arkoma Basin gathering and processing operations serve both rich and lean gas production from more than 80 producers3. Contracts are primarily fee-based contracts with signifjcant support from MVCs, which have a weighted average remaining term of 5.2 years3. We have gathering and processing
- perations in the Ark-La-Tex Basin
located in Arkansas, Louisiana and
- Texas. Our Ark-La-Tex gathering
and processing operations primarily serve the Haynesville, Cotton Valley and the lower Bossier plays. We serve over 100 producers3 in the Ark-La-Tex Basin where
- ur gathering and processing
- perations provide service for both
rich and lean gas production. The scale of Enable’s Ark-La- Tex Basin assets allows us to be well-positioned to supply demand growth from LNG exports. We have operations in the Bakken Shale that are located in North Dakota. The focus of our
- perations in the Williston Basin
is the gathering of crude oil and produced water for XTO Energy Inc., an affjliate of ExxonMobil Corporation, with pipeline gathering systems in Dunn, McKenzie, Williams and Mountrail counties of North Dakota.
4 | Investor Highlights 3
Transportation and Storage
Enable’s Infrastructure Provides Compelling Value for New and Existing Customers
- Contracted or extended over 575,000
Dth/d of transportation capacity during third quarter 2019
- Evaluating asset base optimization
- pportunities
- Entered into a defjnitive agreement to sell
EGT’s undivided 1/12th ownership interest in the Bistineau natural gas storage facility, located in Louisiana for ~$19 million, which is expected to close second quarter 2020
Continued Execution Results in Long-Term Agreements
- Favorable contract structure with signifjcant fee-based
and demand fee margin
- Diverse, high-quality customer base, including many
investment-grade companies
- With fjve3 major projects placed into service since 2015
and two4 additional projects underway, Enable has achieved 2.4 Bcf/d of market solutions for customers
- T&S segment is well-positioned to support natural gas
demand growth in the Mid-continent, Gulf Coast and Southeast regions
1Year-end 2018 weighted average contract life of EGT, MRT, EOIT and SESH 2MRT settlements included as one element the extension of contracts by most of the setting parties for terms that will now end in 2024
Map as of Nov. 4, 2019; Stats as of Dec. 31, 2018
150/50 joint venture with Enbridge Inc. 2Pipeline miles are approximate and interstate/intrastate pipeline miles include ~7,800 miles of interstate pipeline
(including SESH) and ~2,300 miles of intrastate pipeline
3CaSE, Line AD Expansion, Muskogee, Bradley Lateral including Project Wildcat in the G&P segment 4MASS and Gulf Run
Enable Gas Transmission (EGT)
- Enable and CenterPoint Energy Resources Corp. (CERC) have agreed to recontracting terms for a substantial
portion of EGT capacity, which includes nine-year contract terms for the majority of the renewed capacity
- Following a successful open season, EGT signed a 5-year, 100,000 Dth/d precedent agreement in the fourth
quarter of 2019 for the MASS natural gas transportation project, which leverages Enable’s existing infrastructure to address natural gas takeaway limitations by connecting growing production in the Anadarko and Arkoma Basins to delivery points with access to emerging Gulf Coast markets and growing demand markets in the Southeast
Mississippi River Transmission (MRT)
- MRT has agreed to rate case settlement terms with all of MRT’s firm capacity customers that participated in the
pipeline’s recent rate cases, and most of these customers have agreed to extend capacity commitments on MRT through 2024
- MRT expects FERC will rule on the proposed settlements in the first half of 2020, and the pipeline’s new recourse
rates and new negotiated rate agreements will become effective upon FERC approval
- Upon approval of the settlements, MRT will make any necessary refunds to customers and recognize as income any
amounts that have been reserved but not refunded
- Assuming the settlements are approved in 2020, MRT expects revenues for 2020 to be higher than the revenues
MRT recognized in 2018
Gulf Run Pipeline
- Enable anticipates filing a formal certificate application for the project in early 2020
- Project expected to be placed into service by late 2022, subject to FERC approval
EOIT EGT MRT SESH1 Gulf Run 10,100 Miles
Interstate/Intrastate Pipelines2
84.5 Bcf
Natural Gas Storage Capacity Transportation Contract Life in Years Year-End 20181 3.65 5 5 9 20 MRT Contracts2 MASS CERC Extension Gulf Run
Large-Scale, Top-Tier Integrated Assets Provide Unique Market Solutions for Many Sources of Supply and Demand
6 | Investor Highlights 5
Key Takeaways 2020 Outlook
2020 Operational Outlook
Natural Gas Gathered Volumes (TBtu/d) 4.5 – 5.1 Anadarko 2.2 – 2.4 Arkoma 0.4 – 0.5 Ark-La-Tex 1.9 – 2.2 Natural Gas Processed Volumes (TBtu/d)2 2.2 – 2.8 Anadarko 2.0 – 2.3 Arkoma 0.05 – 0.15 Ark-La-Tex 0.2 – 0.3 Crude Oil/Condensate – Throughput Volumes (MBbl/d)3 140 – 170 Anadarko 100 – 120 Williston 40 – 50 Interstate Firm Contracted Capacity (Bcf/d) 5.7 – 6.1
2020 Financial Outlook
Net Income Attributable to Common Units $385 – $445 Interest Expense $175 – $195 Adjusted EBITDA4 $1,050 – $1,150 Series A Preferred Unit Distributions5 $36 Adjusted Interest Expense4 $170 – $190 Maintenance Capital $110 – $130 Distributable Cash Flow4 $720 – $800 Distribution Coverage Ratio6 +/- 1.3x Total Debt / Adjusted EBITDA4 +/- 4.0x
2020 Expansion Capital Outlook
Gathering and Processing Segment $120 – $180 Transportation and Storage Segment $40 – $60 Total Expansion Capital $160 – $240
2020 Price Assumptions
Natural Gas – Henry Hub ($/MMBtu) $2.40 – $2.70 NGLs – Mont Belvieu, Texas ($/gal)7 $0.40 – $0.50 NGLs – Conway, Kansas ($/gal)7 $0.35 – $0.45 Crude Oil – WTI ($Bbl) $50.00 – $60.00
$ in millions $ in millions
1Our 2020 outlook was provided on Nov. 6, 2019, and delivery of this presentation should not be viewed as a reaffirmation of such guidance 2Includes volumes under third-party processing arrangements 3Crude Oil/Condensate throughput includes crude oil and condensate gathered and transported on Enable’s crude oil and condensate
gathering and transportation systems
4Non-GAAP financial measures are reconciled to the nearest GAAP financial measures on page 9 5In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available
cash with respect to the quarter immediately preceding the quarter in which the distribution is made
6Non-GAAP measure calculated as distributable cash flow divided by distributions related to common 7NGL composite based on assumed composition of 45%, 30%, 10%, 5% and 10% for ethane, propane, normal butane, isobutane and
natural gasoline, respectively
1Based off of guided ranges 2Calculation based off of 2019E and 2020E midpoints 3Gross margin profile represents hedges as of Oct. 18, 2019, and Enable’s internal 2020 forecast and price assumptions 4Non-GAAP financial measures are reconciled to the nearest GAAP finanical measures on page 10 5TTM represents three-months ended Sept. 30, 2019, June 30, 2019, March 31, 2019 and Dec. 31, 2018
$425 $325 $160 $240 2020E1 2019E1 47%
Reduction2
Expansion Capital Expenditures 2020 Gross Margin Profjle3 Cost Discipline
~91% Fee-Based or Hedged Margin Gross Margin4 O&M & G&A % Gross Margin Fee-based Volume Dependent Commodity-Based Hedged Commodity-Based Unhedged Fee-based Demand
2016 $1,255 $1,422 $1,612 $1,737 37% 33% 31% 30% 2017 2018 TTM5
Looking ahead to 2020
- Continue to optimize and leverage
- ur large-scale, diversifjed business
footprint
- Committed to aligning operating
expenses and capital expenditures with the business environment
- Anticipate strong distribution coverage
- f approximately 1.3x for 2020, with
the ability to self-fund the vast majority
- f 2020 expansion capital with excess
distributable cash fmow
- Continued focus on executing
announced growth projects, including Gulf Run and MASS, on time and within budget
2020 outlook as of Nov. 6, 20191
8 | Investor Highlights 7
Non-GAAP Reconciliations Forward-looking Statements
Reconciliation of Adjusted EBITDA and Distributable cash fmow to net income attributable to limited partners and calculation of Distribution coverage ratio: 2020 Outlook (In millions) Net income attributable to limited partners1 $421 - $481 Depreciation and amortization expense $420 - $440 Interest expense, net of interest income $175 - $195 Income tax (benefjt) expense $0 - $2 Distributions received from equity method affjliate in excess of equity earnings $5 - $15 Non-cash equity based compensation $15 - $20 Change in fair value of derivatives2 $0 - $10 Adjusted EBITDA $1,050 - $1,150 Series A Preferred Unit distributions3 $36 Adjusted interest expense $170 - $190 Maintenance capital expenditures $110 - $130 Other $0 - $10 DCF $720 - $800 Three Months Ended Year Ended
- Sept. 30,
June 30,
- Mar. 31,
- Dec. 31,
- Dec. 31,
Reconciliation of Gross margin to Total Revenues: 2019 2019 2019 2018 2018 2017 2016 (In millions) Consolidated Product sales $ 320 $ 393 $ 443 $ 609 $ 2,106 $ 1,653 $ 1,172 Service revenue 379 342 352 341 1,325 1,150 1,100 Total Revenues 699 735 795 950 3,431 2,803 2,272 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 263 317 378 484 1,819 1,381 1,017 Gross margin $ 436 $ 418 $ 417 $ 466 $ 1,612 $ 1,422 $ 1,255 Reportable Segments Gathering and Processing Product sales $ 294 $ 379 $ 423 $ 605 $ 2,016 $ 1,538 $ 1,081 Service revenue 248 208 207 203 802 632 559 Total Revenues 542 587 630 808 2,818 2,170 1,640 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 238 297 360 479 1,741 1,285 915 Gross margin $ 304 $ 290 $ 270 $ 329 $ 1,077 $ 885 $ 725 Transportation and Storage Product sales $ 100 $ 114 $ 167 $ 183 $ 625 $ 621 $ 479 Service revenue 134 138 149 142 537 525 545 Total Revenues 234 252 316 325 1,162 1,146 1,024 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 102 123 169 190 628 604 492 Gross margin $ 132 $ 129 $ 147 $ 135 $ 534 $ 542 $ 532 Reconciliation of Adjusted interest expense to Interest expense: 2020 Outlook (In millions) Interest expense, net of interest income $175 - $195 Amortization of premium on long-term debt $0 - $2 Capitalized interest on expansion capital $0 - $2 Amortization of debt expense and discount ($3 - $7) Adjusted interest expense $170 - $190
Some of the information in this presentation may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of fjnancial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation include our expectations of plans, strategies, objectives, growth and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this presentation and in our Annual Report on Form 10-K for the year ended December 31, 2018 (“Annual Report”). Those risk factors and other factors noted throughout this presentation and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.
*Enable is unable to present a quantitative reconciliation of forward-looking Adjusted EBITDA to net cash provided by operating activities because certain information needed to make a reasonable forward-looking estimate of changes in working capital which may (provide) use cash during the calendar year 2020 cannot be reliably predicted and the estimate is often dependent on future events which may be uncertain or outside of Enable’s control. This includes changes to accounts receivable, accounts payable and other changes in non-current assets and liabilities.
1Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common
units outlook
2Change in fair value of derivatives includes changes in the fair value of derivatives that are note designated as hedging instruments 3In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with
respect to the quarter immediately preceding the quarter in which the distribution is made
Non-GAAP Financial Measures
Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio are not fjnancial measures presented in accordance with GAAP. Enable has included these non-GAAP fjnancial measures in this presentation based on information in its consolidated fjnancial statements. Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio are supplemental fjnancial measures that management and external users of Enable’s fjnancial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:
- Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream
energy industry, without regard to capital structure or historical cost basis;
- The ability of Enable’s assets to generate suffjcient cash fmow to make distributions to its partners;
- Enable’s ability to incur and service debt and fund capital expenditures; and
- The viability of acquisitions and other capital expenditure projects and the returns on investment
- f various investment opportunities.
This presentation includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and Distributable cash fmow to net income attributable to limited partners and Adjusted interest expense to interest expense, the most directly comparable GAAP fjnancial measures, as applicable, for each of the periods indicated. Distribution coverage ratio is a fjnancial performance measure used by management to refmect the relationship between Enable’s fjnancial operating performance and cash distributions. Enable believes that the presentation of Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio provides information useful to investors in assessing its fjnancial condition and results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio should not be considered as alternatives to net income, operating income, revenue, cash fmow from operating activities or any other measure of fjnancial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash fmow and Distribution coverage ratio may be defjned differently by other companies in Enable’s industry, Enable’s defjnitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 10 | Investor Highlights 9
Investor Relations
(405) 558-4600 ir@enablemidstream.com Investors.EnableMidstream.com