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

Enable Midstream Partners, LP

Third Quarter 2019 Conference Call

November 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.

2

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, 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, Enable’s definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Enable Highlights

4

• Achieved a distribution coverage ratio of 1.40x1, funding a significant portion of third quarter 2019 expansion

capital

• Reported higher natural gas transported volumes, interstate firm contracted capacity and crude oil and condensate

gathered volumes compared to third quarter 2018

• Made significant progress in settlement discussions with key customers in the Enable Mississippi River

Transmission, LLC (MRT) rate case

• Contracted or extended over 575,000 dekatherms per day (Dth/d) of transportation capacity during third quarter

2019 and signed a precedent agreement in October 2019 for the Merge, Arkoma, SCOOP and STACK (MASS) natural gas transportation project

• Declared quarterly cash distributions of $0.3305 per unit on all outstanding common units and $0.625 on all
• utstanding Series A Preferred Units
• 1. A non-GAAP measure calculated as distributable cash flow divided by distributions related to common units

Delhi Compressor Station

Gathering and Processing

5

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 Oct. 28, 2019; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering systems 2. Since Enable’s formation in May 2013

31

Active Rigs on Enable’s Footprint1

• 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

Rig Activity Updates 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 SCOOP recently came online, achieving total volumes in October of over 180 MMcf/d

‒

Multi-well pads in the STACK recently came online, achieving total volumes in September of over 90 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:

• Total volumes were at nearly 90% of MVC threshold levels over

the last year of Haynesville MVCs that expired in Q3-19

• Enable’s Ark-La-Tex Basin assets are well-positioned to supply

demand growth from LNG exports Williston:

• Record quarterly crude oil gathered volumes2

3 17 2 6 3

STACK SCOOP Granite Wash Ark-La-Tex Williston

3.65 5 5 9 20

Year-End 2018 MRT Contracts MASS CERC Extension Gulf Run

Transportation Contract Life in Years

Transportation and Storage Highlights

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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 opportunities

‒

Entered into a definitive 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

1

Continued Execution Resulting in Long-Term Agreements

1. Year-end 2018 weighted average contract life of EGT, MRT, EOIT and SESH 2. MRT settlements included as one element the extension of contracts by most of the settling parties for terms that will now end in 2024

• 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 that leverages Enable’s existing infrastructure to address natural gas takeaway limitations by connecting production in the Anadarko and Arkoma Basins to delivery points with access to emerging Gulf Coast markets and growing demand markets in the Southeast Enable Gas Transmission (EGT)

• MRT filed proposals with FERC Nov. 5, 2019, to settle the rate cases with customers holding 97% of MRT’s firm subscribed

transportation capacity; most of these customers agreed to extend capacity commitments on MRT through 2024

• A new rate case was filed Oct. 30, 2019, that was necessitated by the customers representing the remaining 3% of MRT’s firm

subscribed transportation capacity to establish new maximum recourse rates for the non-settling parties Mississippi River Transmission (MRT)

• 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

Gulf Run Pipeline

2

Transportation and Storage Overview

7

Map as of Nov. 4, 2019 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. CaSE, Line AD Expansion, Muskogee, Bradley Lateral and including Project Wildcat in the G&P segment 3. MASS and Gulf Run

Favorable contract structure with significant fee-based and demand fee margin Diverse, high-quality customer base, including many investment-grade companies With five2 major projects placed into service since 2015 and two3 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

Large Scale, Top-Tier Integrated Assets Provide Unique Market Solutions for Many Sources of Supply and Demand

10,100 Miles

Interstate/Intrastate Pipelines1

84.5 Bcf

Natural Gas Storage Capacity

EOIT EGT

Gulf Run

Operational and Financial Results

5.40 5.97 Q3-18 Q3-19 31.87 132.99 Q3-18 Q3-19

0.4%

Decrease

3.0%

Decrease

2.50 2.49 Q3-18 Q3-19 4.61 4.47 Q3-18 Q3-19

10.6%

Increase

Operational Performance Overview

9

Transported Volumes Natural Gas Gathered Volumes Natural Gas Processed Volumes

TBtu/d TBtu/d TBtu/d

• Natural gas gathered volumes decreased for third quarter 2019 compared to third quarter 2018 primarily as a result of lower

gathered volumes in the Arkoma and Anadarko Basins

• Natural gas processed volumes decreased for third quarter 2019 compared to third quarter 2018 primarily as a result of lower

processed volumes in the Anadarko Basin, partially offset by higher processed volumes in the Ark-La-Tex Basin

• Crude oil and condensate gathered volumes increased for third quarter 2019 compared to third quarter 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 third quarter 2019 compared to third 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

101.12 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

Q3-19 Q3-18 % Change

Total Revenues $699 $928 25% Gross Margin1 $436 $412 6% Net Income Attributable to Limited Partners $132 $138 4% Net income Attributable to Common Units $123 $129 5% Net Cash provided by Operating Activities $264 $233 13% Adjusted EBITDA1 $295 $301 2% Distributable Cash Flow1 $202 $220 8% Distribution Coverage Ratio2 1.40x 1.60x 0.20x Cash Distribution per Common Unit $0.3305 $0.3180 4% Cash Distribution per Series A Preferred Unit $0.625 $0.625

Financial Results

2020 Outlook and Key Takeaways

2020 Outlook

12

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)1 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)2 140 – 170 Anadarko 100 – 120 Williston 40 – 50 Interstate Firm Contracted Capacity (Bcf/d) 5.7 – 6.1

2020 Operational Outlook 2020 Financial Outlook

$ in millions

Net Income Attributable to Common Units $385 – $445 Interest Expense $175 – $195 Adjusted EBITDA3 $1,050 – $1,150 Series A Preferred Unit Distributions4 $36 Adjusted Interest Expense3 $170 – $190 Maintenance Capital $110 – $130 Distributable Cash Flow3 $720 – $800 Distribution Coverage Ratio5 +/- 1.3x Total Debt / Adjusted EBITDA3 +/- 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

2020 Price Assumptions

Natural Gas – Henry Hub ($/MMBtu) $2.40 – $2.70 NGLs – Mont Belvieu, Texas ($/gal)6 $0.40 – $0.50 NGLs – Conway, Kansas ($/gal)6 $0.35 – $0.45 Crude Oil – WTI ($Bbl) $50.00 – $60.00

• 1. Includes volumes under third-party processing arrangements
• 2. Crude Oil/Condensate throughput includes crude oil and condensate gathered and transported on Enable’s crude oil and condensate gathering and transportation systems
• 3. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
• 4. 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

• 5. Non-GAAP measure calculated as distributable cash flow divided by distributions related to common
• 6. NGL composite based on assumed composition of 45%, 30%, 10%, 5% and 10% for ethane, propane, normal butane, isobutane and natural gasoline, respectively

$325 $160 $425 $240 2019E 2020E

Key Takeaways

13

• Committed to aligning operating expenses and capital expenditures with the

business environment

• Anticipate strong distribution coverage of approximately 1.3x for 2020, with

the ability to self-fund the majority of 2020 expansion capital with excess distributable cash flow

• Continued focus on executing announced growth projects, including Gulf

Run and MASS, on time and within budget

• 1. Based off of guided ranges
• 2. Calculation based off of 2019E and 2020E midpoints
• 3. Gross margin profile represents hedges as of Oct. 18, 2019, and Enable’s latest internal 2020 forecast and price assumptions
• 4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
• 5. TTM represents three-months ended Sep. 30, 2019, June 30, 2019, March 31, 2019 and Dec. 31, 2018

Looking ahead to 2020

Cost Discipline 2020 Gross Margin Profile3 Expansion Capital Expenditures

51% 38% 2% 9%

Volume Dependent Demand Commodity-Based Hedged Commodity-Based Unhedged

~91% Fee-Based or Hedged Margin

1 1

$1,255 $1,422 $1,612 $1,737 37% 33% 31% 30%

2016 2017 2018 TTM

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

5 4

Question and Answer Question and Answer

Appendix Appendix

Commodity Derivative Activity and Price Sensitivities

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• 1. Price sensitivities are based on Enable’s internal forecast and price assumptions and hedges as of Oct. 18, 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 Oct. 18, 2019; table excludes a de minimis amount of hedged 2021 exposure

• 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 September 30 2019 2018 Gain (Loss) on Derivative Activity $8 ($24)

Change in Fair Value of Derivatives ($2) ($16) Realized Gain on Derivatives $10 ($8)

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

Commodity 2019 2020 Natural Gas (NYMEX) Exposure Hedged (%) 74% 13% Average Hedge Price ($/MMBtu) $2.85 $2.94 Natural Gas Basis (PEPL / EGTE) Exposure Hedged (%) 65% 30% Average Hedge Price ($/MMBtu) $(0.45) $(0.40) Crude4 Exposure Hedged (%) 91% 38% Average Hedge Price ($/Bbl) $60.25 $62.22 Propane Exposure Hedged (%) 52% 12% Average Hedge Price ($/gal) $0.71 $0.75 Normal Butane Exposure Hedged (%) 16% 0% Average Hedge Price ($/gal) $0.90

• Net Income2

Adjusted EBITDA (including hedges)

2019 2020

(10%) / +10% (10%) / +10% Natural Gas and Ethane $0 / $0 ($9) / $9 NGLs (excluding ethane) and Condensate ($2) / $2 ($8) / $8

2019 2020

(10%) / +10% (10%) / +10% Natural Gas and Ethane ($2) / $1 ($8) / $8 NGLs (excluding ethane) and Condensate ($2) / $2 ($7) / $7

Gathering and Processing Segment Results

17

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

Operational Results

Quarter over Quarter Q3-19 Q3-18 % Change

Anadarko Basin Gathered Volumes (TBtu/d) 2.27 2.31 2% Processed Volumes (TBtu/d)1 2.04 2.08 2% NGLs Produced (MBbl/d)1,2 103.53 124.80 17% Crude Oil and Condensate Gathered Volumes (MBbl/d) 91.58

• Arkoma Basin

Gathered Volumes (TBtu/d) 0.46 0.56 18% Processed Volumes (TBtu/d) 1 0.10 0.10 NGLs Produced (MBbl/d) 1,2 4.42 7.04 37% Ark-La-Tex Basin Gathered Volumes (TBtu/d) 1.74 1.74 Processed Volumes (TBtu/d) 0.35 0.32 9% NGLs Produced (MBbl/d) 2 9.83 10.16 3% Williston Basin Crude Oil Gathered Volumes (MBbl/d) 41.41 31.87 30%

Financial Results ($ in millions)

Total G&P Total Revenues3 $542 $778 30% Gross Margin3,4 $304 $285 7% Operation & Maintenance and G&A Expenses3 $79 $78 1% Depreciation and Amortization $77 $66 17% Taxes other than Income Tax $10 $9 11% Operating Income $138 $132 5%

Transportation and Storage Segment Results

18

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

Operational Results

Quarter over Quarter Q3-19 Q3-18 % Change

Transported Volumes (Tbtu/d) 5.97 5.40 11% Interstate Firm Contracted Capacity (Bcf/d) 6.02 5.76 5% Intrastate Average Deliveries (TBtu/d) 2.10 2.02 4%

Financial Results ($ in millions)

Total Revenues1 $234 $281 17% Gross Margin1,2 $132 $129 2% Operation & Maintenance and G&A Expenses1 $57 $48 19% Depreciation and Amortization $31 $34 9% Taxes other than Income Tax $7 $6 17% Operating Income $37 $41 10%

Consolidated Statements of Income

19

Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (In millions, except per unit data)

Revenues (including revenues from affiliates): Product sales $ 320 $ 553 $ 1,156 $ 1,497 Service revenue 379 375 1,073 984 Total Revenues 699 928 2,229 2,481 Cost and Expenses (including expenses from affiliates): Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 263 516 958 1,335 Operation and maintenance 105 98 307 289 General and administrative 31 28 82 81 Depreciation and amortization 108 100 323 292 Taxes other than income tax 17 15 52 48 Total Cost and Expenses 524 757 1,722 2,045 Operating Income 175 171 507 436 Other Income (Expense): Interest expense (48) (40) (142) (109) Equity in earnings of equity method affiliate 5 7 12 20 Other, net 1 1 2 1 Total Other Expense (42) (32) (128) (88) Income Before Income Tax 133 139 379 348 Income tax benefit — — (1) — Net Income $ 133 $ 139 $ 380 $ 348 Less: Net income attributable to noncontrolling interest 1 1 2 1 Net Income Attributable to Limited Partners $ 132 $ 138 $ 378 $ 347 Less: Series A Preferred Unit distributions 9 9 27 27 Net Income Attributable to Common Units $ 123 $ 129 $ 351 $ 320 Basic earnings per unit Common units $ 0.28 $ 0.30 $ 0.81 $ 0.74 Diluted earnings per unit Common units $ 0.28 $ 0.30 $ 0.81 $ 0.73

Non-GAAP Reconciliations

20

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

Reconciliation of Gross margin to Total Revenues: Consolidated Product sales $ 320 $ 553 $ 393 $ 443 $ 609 $ 2,106 $ 1,653 $ 1,172 Service revenue 379 375 342 352 341 1,325 1,150 1,100 Total Revenues 699 928 735 795 950 3,431 2,803 2,272 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 263 516 317 378 484 1,819 1,381 1,017 Gross margin $ 436 $ 412 $ 418 $ 417 $ 466 $ 1,612 $ 1,422 $ 1,255 Reportable Segments Gathering and Processing Product sales $ 294 $ 528 $ 379 $ 423 $ 605 $ 2,016 $ 1,538 $ 1,081 Service revenue 248 250 208 207 203 802 632 559 Total Revenues 542 778 587 630 808 2,818 2,170 1,640 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 238 493 297 360 479 1,741 1,285 915 Gross margin $ 304 $ 285 $ 290 $ 270 $ 329 $ 1,077 $ 885 $ 725 Transportation and Storage Product sales $ 100 $ 153 $ 114 $ 167 $ 183 $ 625 $ 621 $ 479 Service revenue 134 128 138 149 142 537 525 545 Total Revenues 234 281 252 316 325 1,162 1,146 1,024 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 102 152 123 169 190 628 604 492 Gross margin $ 132 $ 129 $ 129 $ 147 $ 135 $ 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 three and nine months ended Sept. 30, 2019 and 2018. 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

• utstanding for the quarter ended Sept.

30, 2019

Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (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 $ 132 $ 138 $ 378 $ 347 Depreciation and amortization expense 108 100 323 292 Interest expense, net of interest income 48 40 141 109 Income tax benefit — — (1) — Distributions received from equity method affiliate in excess of equity earnings (1) 3 8 11 Non-cash equity-based compensation 4 4 13 12 Change in fair value of derivatives (1) 2 16 3 28 Other non-cash losses (2) 2 — 9 4 Noncontrolling Interest Share of Adjusted EBITDA — — (1) — Adjusted EBITDA $ 295 $ 301 $ 873 $ 803 Series A Preferred Unit distributions (3) (9) (9) (27) (27) Distributions for phantom and performance units (4) (1) (1) (10) (5) Adjusted interest expense (5) (47) (41) (143) (114) Maintenance capital expenditures (36) (30) (86) (70) DCF $ 202 $ 220 $ 607 $ 587 Distributions related to common unitholders (6) $ 144 $ 138 $ 426 $ 414 Distribution coverage ratio 1.40 1.60 1.42 1.42

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 September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (In millions)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 264 $ 233 $ 691 $ 638 Interest expense, net of interest income 48 40 141 109 Net income attributable to noncontrolling interest (1) (1) (2) (1) Other non-cash items(1) — — 4 4 Proceeds from insurance — — — 1 Changes in operating working capital which (provided) used cash: Accounts receivable 41 46 (16) 58 Accounts payable (2) — 110 19 Other, including changes in noncurrent assets and liabilities (56) (36) (66) (64) Return of investment in equity method affiliate (1) 3 8 11 Change in fair value of derivatives (2) 2 16 3 28 Adjusted EBITDA $ 295 $ 301 $ 873 $ 803

Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest expense $ 48 $ 40 $ 142 $ 109 Interest income — — (1) — Amortization of premium on long-term debt 1 1 4 4 Capitalized interest on expansion capital — — 1 4 Amortization of debt expense and discount (2) — (3) (3) Adjusted interest expense $ 47 $ 41 $ 143 $ 114

2020 Forward-Looking Non-GAAP Reconciliation

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 Reconciliation 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