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

Enable Midstream Partners, LP

Second Quarter 2019 Conference Call

August 6, 2019

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, 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.

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Non-GAAP Financial Measures

3

Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow 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, Distributable cash flow 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 Distributable cash flow 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, Distributable cash flow 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, Distributable cash flow 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 other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow 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 flow and Distribution coverage ratio may be defined differently by other companies in Enable’s industry and Enable’s definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Enable Second Quarter 2019 Highlights

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• Higher natural gas gathered, natural gas processed, crude oil and condensate gathered and natural gas

transported volumes compared to second quarter 2018

• Higher quarterly gross margin, net income, Adjusted EBITDA and distributable cash flow (DCF) compared

to second quarter 20181

• Declared quarterly cash distributions of $0.3305 per unit on all outstanding common units, a one-time

increase of approximately 4% compared to first quarter 2019, and $0.625 on all outstanding Series A Preferred Units

• Achieved a distribution coverage ratio of 1.37x2

Westdale Compressor Station

• 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

1.01x 1.18x 1.20x 1.38x 1.30x 1.45x 2015 2016 2017 2018 2019E $538 $639 $660 $760 $740 $810 2015 2016 2017 2018 2019E

Business Performance Drives Distribution Increase

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• Enable has been growing DCF and distribution coverage each year since 2015 as a result of strong

business performance and a focus on cost discipline

• Enable has self-funded a significant portion of its expansion capital program since 2015, which has

included the completion of new projects and acquisitions in key areas

• Given Enable’s financial performance, Enable is in a position to return additional cash to investors

by increasing its distribution

• With this distribution increase, Enable generated a distribution coverage ratio of 1.37x for the quarter

and still expects to meet its 2019 outlook target of 1.30x to 1.45x

1. 2019E is based on the 2019 Distributable Cash Flow and Distribution Coverage Outlook provided Nov. 7, 2018, reaffirmed Aug. 6, 2019 2. Calculation is based off of 2019E midpoint

~4% Common Unit Distribution Increase Returns Cash to Unitholders History of Strengthening Distribution Coverage Steadily Growing Distributable Cash Flow

1 1

$ in millions

5 27 1 8 3

STACK SCOOP Granite Wash Ark-La-Tex Williston

Gathering and Processing 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 DrillingInfo as of Aug. 5, 2019; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering systems 2. Source: DrillingInfo 3. Since Enable’s formation in May 2013

44

Active Rigs on Enable’s Footprint1

Rig Activity Remains Strong

• Rig activity remains strong around Enable’s gathering

footprint with 44 rigs1 currently drilling wells expected to be connected to Enable’s gathering systems

• 51% of all active rigs in the SCOOP and STACK plays

are drilling wells expected to be connected to Enable’s gathering systems1

• Operators have reduced the number of days it takes

to drill a well in the SCOOP and STACK by an average of 11% between first and second quarter 20192

• Increased crude oil and condensate gathered volumes compared to Q1-19
• Significant natural gas and crude oil midstream infrastructure positions Enable to capitalize on shifting rig activity from the STACK

to the SCOOP Anadarko Basin

• Scale of Ark-La-Tex Basin assets has allowed Enable to benefit from an opportunistic short-term offload agreement
• Enable’s Ark-La-Tex Basin assets are well-positioned to supply demand growth from LNG exports

Ark-La-Tex Basin

• Record quarterly crude oil gathered volumes3
• DUC count is building as a result of third-party natural gas infrastructure constraints that are expected to be alleviated as new

infrastructure comes online later this year Williston Basin

Transportation and Storage Highlights

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• Enable and CenterPoint Energy Resources Corp. (CERC) previously signed precedent agreements outlining terms and

conditions for extending EGT pipeline contracts, which currently expire March 31, 2021; CERC has received the required regulatory approvals, and EGT is preparing the definitive long-term contracts Enable Gas Transmission (EGT)

• The MRT rate case hearing date that was originally set for November 2019 has been rescheduled to early 2020
• MRT remains focused on ensuring that the pipeline’s rates appropriately reflect historical investments and current costs

Mississippi River Transmission (MRT)

• As part of the FERC pre-filing process, Enable hosted public open houses for stakeholders in May 2019
• In June 2019, the commission conducted public scoping meetings for the project
• Enable remains in active discussions with customers for additional capacity commitments and anticipates finalizing the

scope of the project and filing a formal certificate application in early 2020 Gulf Run Pipeline

Unique Market Solutions for Growing Supply and Demand

• Contracted or extended over 600,000 Dth/d of

transportation capacity during second quarter 2019

• Producers continue to request solutions to move

Anadarko Basin natural gas production to market

• T&S segment provides significant, fee-based margin and

is well-positioned to support natural gas demand growth in the Mid-continent, Gulf Coast and Southeast regions Transported Volumes

14.4%

Increase

5.28 6.04 Q2-18 Q2-19

TBtu/d

Operational and Financial Results

14.4%

Increase

5.28 6.04 Q2-18 Q2-19 30.55 119.34 Q2-18 Q2-19 2.33 2.54 Q2-18 Q2-19 4.43 4.62 Q2-18 Q2-19

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 second quarter 2019 compared to second quarter 2018 primarily as a result of higher

gathered volumes in the Anadarko and Ark-La-Tex Basins

• Natural gas processed volumes increased for second quarter 2019 compared to second quarter 2018 primarily as a result of higher

processed volumes in the Anadarko and Ark-La-Tex Basins

• Crude oil and condensate gathered volumes increased for second quarter 2019 compared to second quarter 2018 primarily as a

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

• Transported volumes increased for second quarter 2019 compared to second quarter 2018 primarily as a result of new contracted

capacity on EGT, including volumes from EGT’s CaSE project

Crude Oil and Condensate Gathered Volumes

MBbls/d

4.3%

Increase

9.0%

Increase 89 MBbls/d Increase

Financial Results

10

• 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

Quarter over Quarter

$ in millions, except per-unit and ratio data

Q2-19 Q2-18 % Change

Total Revenues $735 $805 9% Gross Margin1 $418 $361 16% Net Income Attributable to Limited Partners $124 $95 31% Net income Attributable to Common Units $115 $86 34% Net Cash provided by Operating Activities $212 $239 11% Adjusted EBITDA1 $281 $245 15% Distributable Cash Flow1 $197 $171 15% Distribution Coverage Ratio2 1.37x 1.24x 0.13x Cash Distribution per Common Unit $0.3305 $0.3180 4% Cash Distribution per Series A Preferred Unit $0.625 $0.625

Financial Results

Enable: Built for the Long-term

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Critical link between growing production and downstream markets Diversified asset base with proven value, scale and upside Favorable contract structures with significant fee-based and demand-fee margin Financial flexibility with significant liquidity and investment-grade credit metrics Proven operational and financial track record ~96% Fee-Based or Hedged Margin4 Strong Business Performance Key Enable Highlights Large Scale, Fully-Integrated Midstream Platform1 10,100 Miles

Interstate/Intrastate Pipelines

2.6 Bcf/d

Processing Capacity

13,900 Miles

Gathering Pipelines

84.5 Bcf

Natural Gas Storage Capacity

$ in millions

3

• 1. Pipeline miles are approximate and interstate/intrastate pipeline miles include ~7,800 miles of interstate pipeline (including SESH) and ~2,300 miles of

intrastate pipeline

• 2. Calculation is based off of 2019E midpoint
• 3. 2019E is based on the 2019 Adjusted EBITDA Outlook provided Nov. 7, 2018, reaffirmed Aug. 6, 2019
• 4. Gross margin profile represents hedges as of July 10, 2019, and Enable’s latest internal 2019 forecast and price assumptions for the balance of the year

$1,180

45% 44% 7% 4%

Volume Dependent Demand Commodity-Based Hedged Commodity-Based Unhedged

$801 $873 $924 $1,074 $1,090 2015 2016 2017 2018 2019E

Adjusted EBITDA

Responsible Operator, Community Partner

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Environmental Stewardship Community Focused

Enable employees served

20,925 Hours

in local communities in 2018

Enable honors

Emergency Responders

through the Enable Safety Partner Program

Partnered with the OKC Thunder to build

Basketball Courts

in Oklahoma communities

311 employees volunteered to provide

198,000 Meals

through food banks across Enable’s footprint

Enable and its employees donated $560,000 to United Way agencies across the company’s footprint in 2018

Signatory to INGAA’s

Methane Emissions Commitments

to minimize methane emissions

Focused on

Species Conservation

including Lesser Prairie Chicken and American Burying Beetle

Member of EPA’s voluntary

Natural Gas STAR

program since 2003

Enable received the

Corporate Conservation Partnership Award

from the Arkansas Game and Fish Commission

National Wild Turkey Federation presented Enable with its Energy for Wildlife National Achievement Award

Question and Answer Question and Answer

Appendix Appendix

2019 Outlook

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2019 Financial Outlook

$ in millions

Net Income Attributable to Common Units $435 – $505 Interest Expense $190 – $210 Adjusted EBITDA1 $1,090 – $1,180 Series A Preferred Unit Distributions2 $36 Adjusted Interest Expense1 $195 – $215 Maintenance Capital $105 – $125 Distributable Cash Flow1 $740 – $810 Distribution Coverage Ratio 1.30x – 1.45x Total Debt / Adjusted EBITDA1 +/- 4.0x

2019 Expansion Capital Outlook

$ in millions

Gathering and Processing Segment $290 – $370 Transportation and Storage Segment $35 – $55 Total Expansion Capital $325 – $425

• 1. Financial measures are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures in this 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

2019 outlook provided Nov. 7, 2018, reaffirmed Aug. 6, 2019

Gulf Run Pipeline

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• The Gulf Run Pipeline, backed by cornerstone

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

• As part of the FERC pre-filing process, Enable

hosted public open houses for stakeholders in May 2019

• In June 2019, the commission conducted public

scoping meetings for the project

• Enable remains in active discussions with

customers for additional capacity commitments and anticipates finalizing the scope of the project and filing a formal certificate application in early 2020

• The project is expected to be completed by late

2022 and is subject to FERC approval

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

2018 2022 2019 2021

Gulf Run Project1

Golden Pass FID 1. Map as of July 24, 2019

($1) ($1) $1 $1

Commodity Derivative Activity and Price Sensitivities

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• 1. 2019 price sensitivities are based on Enable’s internal forecast and price assumptions for the balance of the year and hedges as of July 10, 2019
• 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;

percentage hedged includes hedges executed through July 10, 2019; Enable has hedged a de minimis amount of 2021 exposure not shown above

• 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

Three Months Ended June 30 2019 2018 Gain (Loss) on Derivative Activity $16 ($14)

Change in Fair Value of Derivatives $11 ($10) Realized Gain on Derivatives $5 ($4)

Derivative Activity ($ in millions) 2019 Price Sensitivities1 ($ in millions) Hedging Summary3

Commodity 2019 2020 Natural Gas (NYMEX) Exposure Hedged (%) 64% 10% Average Hedge Price ($/MMBtu) $2.89 $2.99 Natural Gas Basis (PEPL / EGTE) Exposure Hedged (%) 60% 30% Average Hedge Price ($/MMBtu) $(0.51) $(0.41) Crude4 Exposure Hedged (%) 60% 19% Average Hedge Price ($/Bbl) $60.17 $64.17 Propane Exposure Hedged (%) 43% 8% Average Hedge Price ($/gal) $0.74 $0.80 Normal Butane Exposure Hedged (%) 18% 0% Average Hedge Price ($/gal) $0.80

• 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

($2) ($3) $2 $3

Gathering and Processing Segment Results

18

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

Operational Results

Quarter over Quarter Q2-19 Q2-18 % Change

Anadarko Basin Gathered Volumes (TBtu/d) 2.33 2.14 9% Processed Volumes (TBtu/d)1 2.08 1.91 9% NGLs Produced (MBbl/d)1,2 112.19 113.75 1% Crude Oil and Condensate Gathered Volumes (MBbl/d) 79.96

• Arkoma

Basin Gathered Volumes (TBtu/d) 0.49 0.56 13% Processed Volumes (TBtu/d) 1 0.10 0.11 9% NGLs Produced (MBbl/d) 1,2 7.02 7.60 8% Ark-La-Tex Basin Gathered Volumes (TBtu/d) 1.80 1.73 4% Processed Volumes (TBtu/d) 0.36 0.31 16% NGLs Produced (MBbl/d) 2 10.89 9.30 17% Williston Basin Crude Oil Gathered Volumes (MBbl/d) 39.38 30.55 29%

Financial Results ($ in millions)

Total G&P Total Revenues3 $587 $641 8% Gross Margin3,4 $290 $230 26% Operation & Maintenance and G&A Expenses3 $75 $76 1% Depreciation and Amortization $78 $63 24% Taxes other than Income Tax $10 $10 Operating Income $127 $81 57%

Transportation and Storage Segment Results

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• 1. Before eliminations upon consolidation
• 2. Non-GAAP financial measure and is reconciled to the nearest GAAP financial measures in this Appendix

Operational Results

Quarter over Quarter Q2-19 Q2-18 % Change

Transported Volumes (Tbtu/d) 6.04 5.28 14% Interstate Firm Contracted Capacity (Bcf/d) 6.38 5.72 12% Intrastate Average Deliveries (TBtu/d) 2.06 1.99 4%

Financial Results ($ in millions)

Total Revenues1 $252 $277 9% Gross Margin1,2 $129 $130 1% Operation & Maintenance and G&A Expenses1 $50 $47 6% Depreciation and Amortization $32 $33 3% Taxes other than Income Tax $7 $6 17% Operating Income $40 $44 9%

Consolidated Statements of Income

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Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions, except per unit data)

Revenues (including revenues from affiliates): Product sales $ 393 $ 501 $ 836 $ 944 Service revenue 342 304 694 609 Total Revenues 735 805 1,530 1,553 Cost and Expenses (including expenses from affiliates): Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 317 444 695 819 Operation and maintenance 99 97 202 191 General and administrative 25 26 51 53 Depreciation and amortization 110 96 215 192 Taxes other than income tax 17 16 35 33 Total Cost and Expenses 568 679 1,198 1,288 Operating Income 167 126 332 265 Other Income (Expense): Interest expense (48) (36) (94) (69) Equity in earnings of equity method affiliate 4 7 7 13 Other, net 1 (2) 1 — Total Other Expense (43) (31) (86) (56) Income Before Income Tax 124 95 246 209 Income tax benefit — — (1) — Net Income $ 124 $ 95 $ 247 $ 209 Less: Net income attributable to noncontrolling interest — — 1 — Net Income Attributable to Limited Partners $ 124 $ 95 $ 246 $ 209 Less: Series A Preferred Unit distributions 9 9 18 18 Net Income Attributable to Common Units $ 115 $ 86 $ 228 $ 191 Basic earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44 Diluted earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44

Non-GAAP Reconciliations

21

Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions)

Reconciliation of Gross margin to Total Revenues: Consolidated Product sales $ 393 $ 501 $ 836 $ 944 Service revenue 342 304 694 609 Total Revenues 735 805 1,530 1,553 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 317 444 695 819 Gross margin $ 418 $ 361 $ 835 $ 734 Reportable Segments Gathering and Processing Product sales $ 379 $ 465 $ 802 $ 883 Service revenue 208 176 415 349 Total Revenues 587 641 1,217 1,232 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 297 411 657 769 Gross margin $ 290 $ 230 $ 560 $ 463 Transportation and Storage Product sales $ 114 $ 149 $ 281 $ 289 Service revenue 138 128 287 267 Total Revenues 252 277 568 556 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 123 147 292 286 Gross margin $ 129 $ 130 $ 276 $ 270

Non-GAAP Reconciliations Continued

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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. All outstanding subordinated units converted into common units on a one-for-one basis

• n Aug. 30, 2017

Three Months Ended June 30, Year Ended December 31, 2019 2018 2018 2017 2016 2015 (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 $ 124 $ 95 $ 521 $ 436 $ 312 $ (752) Depreciation and amortization expense 110 96 398 366 338 318 Interest expense, net of interest income 47 36 152 120 99 90 Income tax expense — — (1) (1) 1 — Distributions received from equity method affiliate in excess of equity earnings — 1 7 5 15 13 Non-cash equity-based compensation 5 3 16 15 13 9 Change in fair value of derivatives(1) (11) 10 (26) (28) 60 8 Other non-cash losses (2) 6 4 7 11 26 1 Impairments — — — — 9 1,134 Non-controlling interest share of Adjusted EBITDA — — — — — (20) Adjusted EBITDA $ 281 $ 245 $ 1,074 $ 924 $ 873 $ 801 Series A Preferred Unit distributions (3) (9) (9) (36) (36) (31) — Distributions for phantom and performance units (4) — (1) (5) (2) — — Adjusted interest expense (5) (49) (38) (159) (123) (103) (102) Maintenance capital expenditures (26) (26) (114) (101) (101) (160) Current income taxes — — — (2) 1 (1) DCF $ 197 $ 171 $ 760 $ 660 $ 639 $ 538 Distributions related to common and subordinated unitholders (6) $ 144 $ 138 $ 552 $ 551 $ 539 $ 534 Distribution coverage ratio 1.37 1.24 1.38 1.20 1.18 1.01

Non-GAAP Reconciliations Continued

23

• 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 June 30, Year Ended December 31, 2019 2018 2018 2017 2016 2015 (In millions)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 212 $ 239 $ 924 $ 834 $ 721 $ 726 Interest expense, net of interest income 47 36 152 120 99 90 Net income attributable to noncontrolling interest — — (2) (1) (1) 19 Current income taxes 1 — — 2 (1) 1 Other non-cash items(1) 4 5 7 4 12 (2) Proceeds from insurance — 1 2 2 — — Changes in operating working capital which (provided) used cash: Accounts receivable (28) 35 11 28 (4) (15) Accounts payable 57 (41) (6) (54) 40 29 Other, including changes in noncurrent assets and liabilities (1) (41) 5 12 (68) (43) Return of investment in equity method affiliate — 1 7 5 15 8 Change in fair value of derivatives(2) (11) 10 (26) (28) 60 8 Non-controlling interest share of Adjusted EBITDA — — — — — (20) Adjusted EBITDA $ 281 $ 245 $ 1,074 $ 924 $ 873 $ 801

Three Months Ended June 30, Year Ended December 31, 2019 2018 2018 2017 2016 2015 (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $ 48 $ 36 $ 152 $ 120 $ 99 $ 90 Interest income (1) — — — — — Amortization of premium on long-term debt 2 2 6 6 6 5 Capitalized interest on expansion capital — 2 6 — 1 10 Amortization of debt expense and discount — (2) (5) (3) (3) (3) Adjusted interest expense $ 49 $ 38 $ 159 $ 123 $ 103 $ 102

2019 Forward Looking Non-GAAP Reconciliation

24

• 1. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
• 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

2019 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 $471 - $541 Depreciation and amortization expense $415 - $430 Interest expense, net of interest income $190 - $210 Income tax (benefit) expense ($2) - $2 Distributions received from equity method affiliate in excess of equity earnings $5 - $10 Non-cash equity based compensation $5 - $10 Change in fair value of derivatives(1) $0 - ($5) Adjusted EBITDA $1,090 - $1,180 Series A Preferred Unit distributions(2) $36 Adjusted interest expense $195 - $215 Maintenance capital expenditures $105 - $125 Other $5 - $6 DCF $740 - $810

2019 Forward Looking Non-GAAP Reconciliation Continued

25 *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 2019 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.

2019 Outlook (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest expense, net of interest income $190 - $210 Amortization of premium on long-term debt $6 - $9 Capitalized interest on expansion capital $3 - $7 Amortization of debt expense and discount ($3 - $7) Adjusted interest expense $195 - $215