Enable Midstream Partners, LP Fourth Quarter 2019 Conference Call - - PowerPoint PPT Presentation

Enable Midstream Partners, LP

Fourth Quarter 2019 Conference Call

February 19, 2020

Forward-looking Statements

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 financial 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, 2019 (“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.

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Non-GAAP Financial Measures

3

Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow (DCF) and Distribution coverage ratio are not financial measures presented in accordance with GAAP. Enable has included these non-GAAP financial measures in this presentation based on information in its consolidated financial statements. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are supplemental financial measures that management and external users of Enable’s financial 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 sufficient cash flow 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 of various investment
• pportunities.

This presentation includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable to limited partners, Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense, the most directly comparable GAAP financial measures, as applicable, for each of the periods indicated. Distribution coverage ratio is a financial performance measure used by management to reflect the relationship between Enable's financial operating performance and cash distributions. Enable believes that the presentation of Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio provides information useful to investors in assessing its financial condition and results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not be considered as alternatives to net income, operating income, revenue, cash flow from operating activities, interest expense or any

• ther measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted

interest expense, DCF 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, DCF and Distribution coverage ratio may be defined differently by other companies in Enable’s industry, Enable’s definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

2019 Enable Highlights

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• Achieved record full-year natural gas gathered, natural gas

processed, natural gas transported, and crude oil and condensate gathered volumes1

• Significantly increased crude oil and condensate gathered

volumes in both the Anadarko and Williston Basins

• Extended the weighted-average remaining firm

transportation contract life for EGT, MRT and EOIT from 3.6 years at year-end 2018 to 4.1 years at year-end 20192

• Agreed to rate case settlement terms with 100% of MRT’s

firm capacity customers that participated in the pipeline’s recent rate cases

• Announced the Merge, Arkoma, SCOOP and STACK (MASS)

natural gas transportation project and continued to develop the Gulf Run Pipeline project

1. Since Enable’s formation in May 2013 2. Contract life weighted by volumes; contracts associated with the MRT rate cases are subject to FERC approval 3. The partnership increased the quarterly distribution rate from $.3180/unit to $.3305/unit, an increase of approximately 4%, beginning with the Q2-19 distribution

Commercial and Operational Achievements

• Higher fourth quarter and full-year 2019 Adjusted EBITDA

and DCF compared to fourth quarter and full-year 2018

• Achieved the upper end of 2019 outlook for Adjusted EBITDA

and DCF

• Focused on capital efficiency, driving expansion capital below

the 2019 outlook range

• Increased the cash return to common unitholders by raising

the quarterly distribution by approximately 4%3

Financial Achievements

Unionville Storage Northern Louisiana

2019: A Year of Continued Execution

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Total Gathered Volumes

+62% since 2016

Business Growth, Cost Discipline and Efficient Capital Deployment “Enabled” the Self-Funding of Nearly 80% of the 2019 Capital Program After Distributions2

1. Enable’s total crude oil and condensate volumes have been converted to an MMBtu equivalent using a conversion factor of 5.80 MMBtus per gathered barrel 2. Self-funding calculated as FY2019 DCF plus FY2019 maintenance capital minus FY2019 common unit distributions. FY2019 Capital Program self-funding percentage calculated by dividing self-funding amount by total FY2019 capital expenditures 3. Non-GAAP financial measure are reconciled to the nearest GAAP financial measures in the Appendix 4. Non-GAAP measure calculated as DCF divided by distributions related to common and subordinated units

Distribution Coverage4

+17% since 2016

Transported Volumes

+27% since 2016

3.28 3.71 4.72 5.31 2016 2017 2018 2019

Tbtu/d Equivalent1

Adjusted EBITDA3

+31% since 2016

4.88 5.04 5.56 6.18 2016 2017 2018 2019

Tbtu/d

$873 $924 $1,074 $1,147 2016 2017 2018 2019

$ in millions

1.18x 1.20x 1.38x 1.38x 2016 2017 2018 2019

3.83x 4.51x 4.51x 4.56x 4.82x 4.89x ENBL Peer A Peer B Peer C Peer D Peer E Debt-to-EBITDA ENBL Peer A $1,255 $1,422 $1,612 $1,681 37% 33% 31% 31%

2016 2017 2018 2019

Gross Margin O&M & G&A % Gross Margin

50% 39% 4% 7%

Fee-Based Volume Dependent Fee-Based Demand Commodity-Based Hedged Commodity-Based Unhedged

Financially Strong and Disciplined

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Highlights

• Continued focus on operating efficiency and cost discipline
• Favorable contract structures with significant fee-based and demand-fee margins
• Committed to aligning expansion capital expenditures with the business environment
• Significant liquidity and investment-grade credit metrics

Strong Financial Position

1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix 2. Gross margin profile represents hedges as of Feb. 14, 2020, and Enable’s latest internal 2020 forecast and price assumptions 3. ENBL leverage is calculated as Total Debt / Adjusted EBITDA and is based off of FY2019 Actuals 4. Source: Bloomberg. Current (as of Feb. 7, 2020) Total Debt / FY2019 Adjusted EBITDA average analyst estimates; Peers include DCP, ENLC, OKE, WES and WMB; Peers shown on graph in order of ascending Debt-to-EBITDA rather than alphabetical order

2020F Gross Margin Profile2 Cost Discipline

~93% Fee-Based or Hedged

1 3 4

Gulf Run Pipeline Project

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• The Gulf Run Pipeline project, backed by a 20-year

commitment from cornerstone shipper Golden Pass LNG, will provide access to some of the most prolific natural gas producing regions in the U.S.

• Expect to file certificate applications with FERC by

the end of first quarter 2020 seeking authorization for the project

• Project scope expected to be filed would provide

approximately 1.7 Bcf/d of capacity, which would both accommodate Golden Pass’s 1.1 Bcf/d commitment and allow for additional capacity subscriptions that may develop from ongoing discussions at an estimated total cost for the filed scope of approximately $640 million1

• Project will be appropriately sized to meet

contracted customer capacity commitments and is expected to be placed into service in late 2022, subject to FERC approval

Project Announcement Open Season Survey Work FERC Pre- Filing Public Open Houses FERC Scoping Meetings FERC 7(c) Filing FERC Approval Begin Construction Project Completed

2018 2022 2019 2021

Gulf Run Pipeline Project

Golden Pass FID Note: Map as of Jan. 27, 2020

• 1. Excludes the estimated allowance for funds used during constructions, which represents the approximate net composite interest cost of borrowed funds and

a reasonable return on the equity funds used for construction

2020

Q4 2019 Commercial Highlights

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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 1. Rigs per Enverus as of Feb. 10, 2020; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering systems 2. Source: Enverus 3. Contracts associated with the MRT rate cases are subject to FERC approval

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Active Rigs on Enable’s Footprint1

• Producers remain active across Enable’s

gathering footprint with 27 rigs1 currently drilling wells expected to be connected to Enable’s gathering systems

‒

47% of all active rigs1 in the SCOOP and STACK plays are drilling wells expected to be connected to Enable’s gathering systems

‒

Operators have reduced the number of days it takes to drill a well in the Anadarko by an average of 17% in Q3-19 compared to Q3-182

• Total crude oil and condensate volumes gathered

reached 153 MBbl/d in Q4-19, driven by continued growth in the Anadarko Basin

Gathering and Processing Transportation and Storage

• Contracted or extended over 1.2 million Dth/d of

transportation capacity during Q4-193

• MRT Rate Case Update:

‒

Agreed to rate case settlement terms with all of MRT’s firm capacity customers that participated in the recent rate cases, with 90% of third-party transportation capacity now extended into 2024

‒

Expect FERC to rule on the proposed settlements in the first half of 2020

‒

Assuming the settlements are approved in 2020, MRT expects revenues for 2020 to be higher than the revenues MRT recognized in 2018, which were unaffected for the rate case or capacity turnbacks

4.7% Increase

5.72 5.99 Q4 2018 Q4 2019

Transported Volumes

TBtu/d

18 1 5 3

SCOOP Granite Wash Ark-La-Tex Williston

Operational and Financial Results

Operational Performance Overview

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Transported Volumes Natural Gas Gathered Volumes Natural Gas Processed Volumes

TBtu/d TBtu/d TBtu/d

• Natural gas gathered volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of higher gathered

volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower gathered volumes in the Arkoma Basin

• Natural gas processed volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of higher

processed volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower processed volumes in the Arkoma Basin

• Crude oil and condensate gathered volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of

Enable’s crude oil and condensate gathering system acquisition in the Anadarko Basin and growth in the Williston Basin

• Transported volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of newly contracted

capacity on EGT, including volumes from EGT’s CaSE project and EOIT’s Muskogee project Crude Oil and Condensate Gathered Volumes 1.8% Increase

4.48 4.56 FY 2018 FY 2019

5.4% Increase

2.40 2.53 FY 2018 FY 2019

87.39 MBbls/d Increase

41.07 128.46 FY 2018 FY 2019

11.2% Increase

5.56 6.18 FY 2018 FY 2019

MBbls/d

Three Months Ended Dec. 31 Year Ended Dec. 31

$ in millions, except per-unit and ratio data

2019 2018 % Change 2019 2018 % Change

Total Revenues $731 $950 23% $2,960 $3,431 14% Gross Margin1 $410 $466 12% $1,681 $1,612 4% Net Income Attributable to Limited Partners $18 $174 90% $396 $521 24% Net income Attributable to Common Units $9 $165 95% $360 $485 26% Net Cash provided by Operating Activities $251 $286 12% $942 $924 2% Adjusted EBITDA1 $274 $271 1% $1,147 $1,074 7% Distributable Cash Flow1 $177 $173 2% $784 $760 3% Distribution Coverage Ratio2 1.23x 1.26x 0.03x 1.38x 1.38x Cash Distribution per Common Unit $0.3305 $0.3180 4% $1.310 $1.272 3% Cash Distribution per Series A Preferred Unit $0.625 $0.625 $2.500 $2.500

Financial Results

Financial Results

11

• 1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
• 2. A non-GAAP measure calculated as distributable cash flow divided by distributions related to common units

2020 Focus

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Strong Financial Position

✔ Focused on maintaining strong distribution coverage and investment-grade credit metrics

Optimization

✔ Continuing to improve efficiency and generate cost savings

Commercial Excellence

✔ Pursuing additional high-value opportunities across the footprint

Capital Discipline

✔ Right-sizing expansion capital program for customer activity

Sustainability Reporting

✔ Planning to expand sustainability disclosures by year-end 2020

1 2 3 4 5

Question and Answer Question and Answer

Appendix Appendix

2020 Outlook

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2020 Financial Outlook

$ in millions

Net Income Attributable to Common Units $385 – $445 Interest Expense $175 – $195 Adjusted EBITDA1 $1,050 – $1,150 Series A Preferred Unit Distributions2 $36 Adjusted Interest Expense1 $170 – $190 Maintenance Capital $110 – $130 Distributable Cash Flow1 $720 – $800 Distribution Coverage Ratio3 +/- 1.3x Total Debt / Adjusted EBITDA1 +/- 4.0x

2020 Expansion Capital Outlook

$ in millions

Gathering and Processing Segment $120 – $180 Transportation and Storage Segment $40 – $60 Total Expansion Capital $160 – $240

• 1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
• 2. In 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

• 3. Non-GAAP measure calculated as distributable cash flow divided by distributions related to common units

2020 outlook provided Nov. 6, 2019, reaffirmed Feb. 19, 2020

($6) ($2) $6 $2 ($5) ($1) $5 $1

Derivative Activity and Price Sensitivities

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• 1. Price sensitivities are based on Enable’s 2020 outlook and hedges as of Feb. 14, 2020
• 2. The impact of price sensitivities is the same for net income attributable to limited partners and net income attributable to common units
• 3. Table includes hedges and commodity exposures associated with equity volumes resulting from Enable’s gathering, processing and transportation businesses;

exposure based on Enable’s 2020 outlook; percentage hedged includes hedges executed through Feb. 14, 2020

• 4. Enable hedges net condensate and natural gasoline exposure with crude; net exposure and the percentage hedged excludes the proportion of long condensate

positions offset by short natural gasoline positions

Year Ended Dec. 31 2019 2018 Gain (Loss) on Derivative Activity $16 $11

Change in Fair Value of Derivatives ($11) $26 Realized Gain (Loss) on Derivatives $27 ($15)

Derivative Activity ($ in millions) 2020 Price Sensitivities1 ($ in millions) Hedging Summary3

Commodity 2020 2021 Natural Gas (NYMEX) Exposure Hedged (%) 35% 2% Average Hedge Price ($/MMBtu) $2.53 $2.65 Natural Gas Basis (PEPL / EGTE) Exposure Hedged (%) 41% 11% Average Hedge Price ($/MMBtu) $(0.38) $(0.29) Crude4 Exposure Hedged (%) 53% 8% Average Hedge Price ($/Bbl) $60.98 $56.22 Propane Exposure Hedged (%) 29% 0% Average Hedge Price ($/gal) $0.61

• Normal Butane

Exposure Hedged (%) 7% 0% Average Hedge Price ($/gal) $0.53

• Net Income2

Adjusted EBITDA (including hedges)

(10%) +10%

Natural Gas and Ethane NGLs (excluding ethane) and Condensate

+10% (10%)

NGLs (excluding ethane) and Condensate Natural Gas and Ethane

Gathering and Processing Segment Results

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• 1. Includes volumes under third-party processing arrangements
• 2. Excludes condensate
• 3. Before eliminations upon consolidation
• 4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix

Operational Results

Three Months Ended Dec. 31 Year Ended Dec. 31 2019 2018 % Change 2019 2018 % Change Anadarko Basin Gathered Volumes (TBtu/d) 2.42 2.38 2% 2.34 2.21 6% Processed Volumes (TBtu/d)1 2.19 2.14 2% 2.10 1.99 6% NGLs Produced (MBbl/d)1,2 116.78 119.92 3% 113.20 113.63 0% Crude Oil and Condensate Gathered Volumes (MBbl/d) 122.23 48.17 154% 92.70 12.14 664% Arkoma Basin Gathered Volumes (TBtu/d) 0.44 0.53 17% 0.47 0.55 15% Processed Volumes (TBtu/d) 1 0.08 0.10 20% 0.09 0.10 10% NGLs Produced (MBbl/d) 1,2 4.04 6.56 38% 5.42 6.55 17% Ark-La-Tex Basin Gathered Volumes (TBtu/d) 1.76 1.71 3% 1.75 1.72 2% Processed Volumes (TBtu/d) 0.30 0.33 9% 0.34 0.31 10% NGLs Produced (MBbl/d) 2 7.63 10.26 26% 9.96 9.80 2% Williston Basin Crude Oil Gathered Volumes (MBbl/d) 30.83 28.42 8% 35.76 28.93 24%

Financial Results ($ in millions)

Total G&P Total Revenues3 $579 $808 28% $2,338 $2,818 17% Gross Margin3,4 $271 $329 18% $1,135 $1,077 5% Operation & Maintenance and G&A Expenses3 $82 $82 $320 $312 3% Depreciation and Amortization $79 $72 10% $308 $263 17% Impairment $86

• $86
• Taxes other than Income Tax

$10 $9 11% $41 $38 8% Operating Income $14 $166 92% $380 $464 18%

Transportation and Storage Segment Results

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• 1. Before eliminations upon consolidation
• 2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix

Operational Results

Three Months Ended Dec. 31 Year Ended Dec. 31 2019 2018 % Change 2019 2018 % Change

Transported Volumes (Tbtu/d) 5.99 5.72 5% 6.18 5.56 11% Interstate Firm Contracted Capacity (Bcf/d) 6.30 6.24 1% 6.31 5.94 6% Intrastate Average Deliveries (TBtu/d) 2.09 2.21 5% 2.14 2.08 3%

Financial Results ($ in millions)

Total Revenues1 $236 $325 27% $1,038 $1,162 11% Gross Margin1,2 $139 $135 3% $547 $534 2% Operation & Maintenance and G&A Expenses1 $55 $48 15% $207 $189 10% Depreciation and Amortization $31 $34 9% $125 $135 7% Taxes other than Income Tax $5 $8 38% $26 $27 4% Operating Income $48 $45 7% $189 $183 3%

Consolidated Statements of Income

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• 1. All outstanding subordinated units converted into common units on a one-for-one basis on Aug. 30, 2017

Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 2017 2016 (In millions, except per unit data)

Revenues (including revenues from affiliates): Product sales $ 377 $ 609 $ 1,533 $ 2,106 $ 1,653 $ 1,172 Service revenue 354 341 1,427 1,325 1,150 1,100 Total Revenues 731 950 2,960 3,431 2,803 2,272 Cost and Expenses (including expenses from affiliates): Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 321 484 1,279 1,819 1,381 1,017 Operation and maintenance 116 99 423 388 369 367 General and administrative 21 32 103 113 95 98 Depreciation and amortization 110 106 433 398 366 338 Impairments 86 — 86 — — 9 Taxes other than income tax 15 17 67 65 64 58 Total Cost and Expenses 669 738 2,391 2,783 2,275 1,887 Operating Income 62 212 569 648 528 385 Other Income (Expense): Interest expense (48) (43) (190) (152) (120) (99) Equity in earnings of equity method affiliate 5 6 17 26 28 28 Other, net 1 (1) 3 — — — Total Other Expense (42) (38) (170) (126) (92) (71) Income Before Income Tax 20 174 399 522 436 314 Income tax expense — (1) (1) (1) (1) 1 Net Income $ 20 $ 175 $ 400 $ 523 $ 437 $ 313 Less: Net income attributable to noncontrolling interest 2 1 4 2 1 1 Net Income Attributable to Limited Partners $ 18 $ 174 $ 396 $ 521 $ 436 $ 312 Less: Series A Preferred Unit distributions 9 9 36 36 36 22 Net Income Attributable to Common and Subordinated Units (1) $ 9 $ 165 $ 360 $ 485 $ 400 $ 290 Basic earnings per unit Common units $ 0.02 $ 0.38 $ 0.83 $ 1.12 $ 0.92 $ 0.69 Subordinated units (1) $ — $ — $ — $ — $ 0.93 $ 0.68 Diluted earnings per unit Common units $ 0.02 $ 0.38 $ 0.82 $ 1.11 $ 0.92 $ 0.69 Subordinated units (1) $ — $ — $ — $ — $ 0.93 $ 0.68

Non-GAAP Reconciliations

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Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 2017 2016 (In millions)

Reconciliation of Gross margin to Total Revenues: Consolidated Product sales $ 377 $ 609 $ 1,533 $ 2,106 $ 1,653 $ 1,172 Service revenue 354 341 1,427 1,325 1,150 1,100 Total Revenues 731 950 2,960 3,431 2,803 2,272 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 321 484 1,279 1,819 1,381 1,017 Gross margin $ 410 $ 466 $ 1,681 $ 1,612 $ 1,422 $ 1,255 Reportable Segments Gathering and Processing Product sales $ 353 $ 605 $ 1,449 $ 2,016 $ 1,538 $ 1,081 Service revenue 226 203 889 802 632 559 Total Revenues 579 808 2,338 2,818 2,170 1,640 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 308 479 1,203 1,741 1,285 915 Gross margin $ 271 $ 329 $ 1,135 $ 1,077 $ 885 $ 725 Transportation and Storage Product sales $ 106 $ 183 $ 487 $ 625 $ 621 $ 479 Service revenue 130 142 551 537 525 545 Total Revenues 236 325 1,038 1,162 1,146 1,024 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 97 190 491 628 604 492 Gross margin $ 139 $ 135 $ 547 $ 534 $ 542 $ 532

Non-GAAP Reconciliations Continued

21

1. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments 2. Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies 3. This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the periods presented. The year-ended 2016 amount includes the prorated quarterly cash distribution on the Series A Preferred Units declared on April 26, 2016. In 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 4. Distributions for phantom and performance units represent distribution equivalent rights paid in cash. Phantom unit distribution equivalent rights are paid during the vesting period and performance unit distribution equivalent rights are paid at vesting 5. See below for a reconciliation of Adjusted interest expense to Interest expense 6. Represents cash distributions declared for common units outstanding as of each respective period. Amounts for 2019 reflect estimated cash distributions for common units outstanding for the quarter ended

• Dec. 31, 2019. All outstanding

subordinated units converted into common units on a one-for-one basis on Aug. 30, 2017

Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 2017 2016 (In millions, except Distribution coverage ratio)

Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio: Net income attributable to limited partners $ 18 $ 174 $ 396 $ 521 $ 436 $ 312 Depreciation and amortization expense 110 106 433 398 366 338 Interest expense, net of interest income 47 43 188 152 120 99 Income tax expense — (1) (1) (1) (1) 1 Distributions received from equity method affiliate in excess of equity earnings — (4) 8 7 5 15 Non-cash equity-based compensation 3 4 16 16 15 13 Change in fair value of derivatives (1) 8 (54) 11 (26) (28) 60 Other non-cash losses (2) 3 3 12 7 11 26 Impairment 86 — 86 — — 9 Non-controlling Interest Share of Adjusted EBITDA (1) — (2) — — — Adjusted EBITDA $ 274 $ 271 $ 1,147 $ 1,074 $ 924 $ 873 Series A Preferred Unit distributions (3) (9) (9) (36) (36) (36) (31) Distributions for phantom and performance units (4) — — (10) (5) (2) — Adjusted interest expense (5) (48) (45) (191) (159) (123) (103) Maintenance capital expenditures (40) (44) (126) (114) (101) (101) Current income taxes — — — — (2) 1 DCF $ 177 $ 173 $ 784 $ 760 $ 660 $ 639 Distributions related to common and subordinated unitholders (6) $ 144 $ 138 $ 570 $ 552 $ 551 $ 539 Distribution coverage ratio 1.23 1.26 1.38 1.38 1.20 1.18

Non-GAAP Reconciliations Continued

22

• 1. Other non-cash items include amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies
• 2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments

Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 2017 2016 (In millions)

Reconciliation of Adjusted EBITDA to net cash provided by

• perating activities:

Net cash provided by operating activities $ 251 $ 286 $ 942 $ 924 $ 834 $ 721 Interest expense, net of interest income 47 43 188 152 120 99 Net income attributable to noncontrolling interest (2) (1) (4) (2) (1) (1) Current income taxes — — — — 2 (1) Other non-cash items(1) (2) 3 2 7 4 12 Proceeds from insurance 1 1 1 2 2 — Changes in operating working capital which (provided) used cash: Accounts receivable (21) (47) (37) 11 28 (4) Accounts payable (32) (25) 78 (6) (54) 40 Other, including changes in noncurrent assets and liabilities 24 69 (42) 5 12 (68) Return of investment in equity method affiliate — (4) 8 7 5 15 Change in fair value of derivatives (2) 8 (54) 11 (26) (28) 60 Adjusted EBITDA $ 274 $ 271 $ 1,147 $ 1,074 $ 924 $ 873

Three Months Ended December 31, Year Ended December 31, 2019 2018 2019 2018 2017 2016 (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $ 48 $ 43 $ 190 $ 152 $ 120 $ 99 Interest income (1) — (2) — — — Amortization of premium on long-term debt 2 2 6 6 6 6 Capitalized interest on expansion capital 1 2 2 6 — 1 Amortization of debt expense and discount (2) (2) (5) (5) (3) (3) Adjusted interest expense $ 48 $ 45 $ 191 $ 159 $ 123 $ 103

2020 Forward-Looking Non-GAAP Reconciliations

23

• 1. Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common units outlook
• 2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
• 3. In 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

2020 Outlook (In millions)

Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to limited partners and calculation of Distribution coverage ratio: Net income attributable to limited partners (1) $421 - $481 Depreciation and amortization expense $420 - $440 Interest expense, net of interest income $175 - $195 Income tax (benefit) expense $0 - $2 Distributions received from equity method affiliate in excess of equity earnings $5 - $15 Non-cash equity based compensation $15 - $20 Change in fair value of derivatives (2) $0 - $10 Adjusted EBITDA $1,050 - $1,150 Series A Preferred Unit distributions (3) $36 Adjusted interest expense $170 - $190 Maintenance capital expenditures $110 - $130 Other $0 - $10 DCF $720 - $800

2020 Forward-Looking Non-GAAP Reconciliations Continued

24 *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

• ther changes in non-current assets and liabilities.

2020 Outlook (In millions)

Reconciliation of Adjusted interest expense to Interest expense: 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