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

Enable Midstream Partners, LP

Second Quarter 2019 Investor Presentation

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 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.

1. Enable Midstream Overview 2. Gathering and Processing Segment Overview 4. Transportation and Storage Segment Overview 5. Appendix

4

Contents

Enable Midstream Overview

Fully Integrated Midstream Platform Across Leading Basins

6

Note: Map as of May 7, 2019; pipeline miles are approximate 1. Includes SESH, in which Enable owns a 50% interest

• Significant scale: 7,800 miles of interstate

pipelines1, 2,300 miles of intrastate pipelines, 13,900 miles of gathering systems, 15 major processing plants with 2.6 Bcf/d of processing capacity and 8 natural gas storage facilities comprising 84.5 Bcf of storage capacity

• Fully integrated midstream platform that is a

critical link between growing production and downstream markets

• Assets in prominent natural gas and crude oil

producing basins with a market-leading midstream position in the SCOOP and STACK plays

• Long-term relationships with large-cap

producers and utilities, many of whom are investment grade

• Favorable contract structure with significant

fee-based and demand-fee margin

• Investment grade credit metrics, significant

liquidity, substantial distribution coverage and strong sponsorship

0.0 0.5 1.0 1.5 2.0 2.5 3.0 2017 2018 2019

TBtu/d Equivalent

• Nat. Gas Gathered TBtu/d

Crude Gathered TBtu/d Equivalent

Market-Leading Anadarko Basin Position

7

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. Processing capacity per Bentek as of April 18, 2019 2. Rigs per DrillingInfo as of April 24, 2019 3. Rigs as reported in Enable’s quarterly earnings press releases 4. Enable’s Anadarko Basin crude oil and condensate volumes have been converted to an MMBtu equivalent using a conversion factor of 5.80 MMBtus per barrel

… Drives Crude, Gas Volumes Increasing Producer Activity …3

#1 in Processing Capacity in the SCOOP and STACK1 39% of rigs running in the SCOOP and STACK are dedicated to Enable2 Enable’s Anadarko Basin rig count is at its highest quarterly level since Q1-153 Significant natural gas and crude oil midstream infrastructure positions Enable to capitalize on changing rig activity

Strategically-Advantaged Footprint Supports Growth from Top-Tier Producers

Dedicated Acreage Other Rigs Dedicated Rigs

4 4

20 22 21 5 13 12 19 13 14 5 7 6 15 16 16 16 12 14 10 9 11 22 31 30 35 26 31 38 40 42

Q1-17 Q2-17 Q3-17 Q4-17 Q1-18 Q2-18 Q3-18 Q4-18 Q1-19

Dedicated Rig Count SCOOP Oil or Oil/Gas SCOOP Gas STACK Granite Wash

3

Gulf Run Pipeline

8

• 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.

• Enable continues to pursue opportunities to

increase the size of the project

• On April 12, 2019, Enable received FERC

approval for the request made by Enable Gulf Run and Enable Gas Transmission (EGT) to initiate the FERC’s pre-filing process for the project

• Public open houses for stakeholders are

scheduled for May 2019

• 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 May 7, 2019

5.79 6.67 Q1-18 Q1-19

15.2%

Increase

6.05 6.52 Q1-18 Q1-19

7.8%

Increase

11 27 4 8 2

STACK SCOOP Granite Wash Ark-La-Tx Williston

Other Commercial Highlights

9

1. Rigs per DrillingInfo as of April 24, 2019

• Rig activity remains strong around Enable’s

gathering footprint with 52 rigs1 currently drilling wells expected to be connected to Enable’s gathering systems

‒

Enable expects to gather crude oil and condensate from wells drilled by 44% of these rigs1

• Crude oil and condensate volumes gathered

reached 108 MBbl/d driven by the first full-quarter contribution from the recent Anadarko Basin crude midstream business acquisition and growth

• n Williston Basin assets

52

Active Rigs on Enable’s Footprint1

Gathering and Processing Transportation and Storage

• Contracted or extended over 1 million Dth/d of

transportation capacity during the first quarter of 2019

• All FERC 501-G proceedings for EGT have been

concluded, and EGT’s existing rates remain in effect, unchanged

• Producers continue to request solutions to move

Anadarko Basin natural gas production to market

Interstate Firm Contracted Capacity

Bcf/d

Transported Volumes

TBtu/d

1.18x 1.20x 1.38x 1.30x 0.15x 2016 2017 2018 2019E

Financial Strength and Discipline

10

Distribution Coverage

1. Results from 2016 through 2018 2. Gross margin profile represents hedges as of April 5, 2019, and Enable’s current 2019 forecast and price assumptions 3. 2019E represents Enable’s 2019 outlook ranges provided Nov. 7, 2018, and reaffirmed May 1, 2019

44% 44% 8% 4% Volume Dependent Demand Commodity-Based Hedged Commodity-Based Unhedged

1.45x $873 $924 $1,074 $1,090 $90 2016 2017 2018 2019E

$ in millions

$1,180

Adjusted EBITDA Margin Profile 96% Fee-Based or Hedged2

Investment-Grade Credit Metrics Strong Distribution Coverage Per-Unit DCF Growth Improved Returns on Invested Capital

Enable’s Results Check All of the Boxes1

3 3

31% 13% 23%

EV / 2019 Adjusted EBITDA Distribution Yield Analyst Price Target

Proven Track Record with Upside Potential

11

Strong operational and financial results driven by high-quality assets and a focus on cost discipline and capital efficiency History of developing creative and cost-effective market solutions Financially disciplined with solid distribution coverage and an investment-grade balance sheet Enable Unit Price Appreciation Potential5

Source: Bloomberg market data and peer mean consensus estimates as of May 8, 2019 1. EV / 2019 Adjusted EBITDA equals current Enterprise Value divided by 2019 Adjusted EBITDA; Adjusted EBITDA reduced by General Partner (GP) percentage of distributions for peers with GP distributions 2. Distribution Yield equals most recently announced distribution on an annualized basis divided by May 8, 2019, close price 3. Debt / Adjusted EBITDA equals total current debt divided by TTM Adjusted EBITDA 4. ANGI Index is the Alerian Natural Gas MLP Index 5. See Appendix for Enable Unit Price Appreciation Potential assumptions 6. Median analyst price target from analysts listed on Enable’s Investor Relations website as of May 8, 2019

Compelling Valuation Strong Balance Sheet Attractive Yield Proven Track Record

+22% Average Uplift

6

1 2 3 4

9.5x 3.9x 11.1x 5.0x EV / 2019 Adjusted EBITDA Distribution Yield Debt / Adjusted EBITDA ENBL ANGI Index 8.2% 9.2%

Appendix

Gathering and Processing Segment Overview

Anadarko Basin

13

Note: Operational data as of Dec. 31, 2018 1. Map as of May 7, 2019 2. Rigs per DrillingInfo as of April 24, 2019

• Enable serves over 200 producers in

the Anadarko Basin and has secured 5.4 million gross acres of dedication under long-term, fee-based contracts

• Strong rig activity continues in the

basin with 42 rigs2 drilling wells expected to be connected to Enable’s gathering systems, including 27 rigs2 active in the SCOOP play

• Enable’s natural gas and crude oil

gathering footprint is uniquely positioned to serve the increased drilling activity in the SCOOP play

• Enable's natural gas super-header

system allows Enable to optimize the economics of its natural gas processing, respond quickly to customer needs and efficiently phase in new production

System Highlights System Map1 System Details

Pipeline Miles 8,600 Horsepower of Compression 857,800 Processing Plants 11 Processing Capacity (Bcf/d) 1.845 NGLs Produced (MBbl/d) 113.63 Gross Acres of Dedication 5.4 million

Ark-La-Tex Basin

14

• Enable serves over 100 producers in

the Ark-La-Tex Basin and provides gathering and processing services to both rich and lean gas production in the Haynesville, Cotton Valley and lower Bossier plays

• Assets from the Align Midstream

acquisition were connected to Enable’s Waskom Plant Nov. 1, 2018, enabling further optimization of the basin’s midstream platform

• Enable’s Ark-La-Tex Basin assets are

well-positioned to supply demand growth from LNG exports and electric utilities

• Eight rigs1 are currently drilling wells

that are expected to be connected to Enable’s gathering systems

System Map

2

System Highlights

Note: Operational data as of Dec. 31, 2018 1. Per Drillinginfo as of April 24, 2019 2. Map as of May 7, 2019

System Details

Pipeline Miles 1,800 Horsepower of Compression 160,200 Processing Plants 3 Processing Capacity (Bcf/d) 0.645 Fractionation Capacity (MBbl/d) 14.5 NGLs Produced (MBbl/d) 9.8 Gross Acres of Dedication 1.2 million

Arkoma Basin

15

System Map1 System Highlights

• Enable serves over 80 producers in the

Arkoma Basin and provides gathering and processing services to both rich and lean gas production in the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas

• Contracts are primarily fee-based

contracts with significant support from MVCs

• 5% of G&P gross margin is

attributable to Arkoma Basin natural gas gathering contracts with MVCs that have a volume commitment- weighted average remaining term of 5.2 years2

Note: Operational data as of Dec. 31, 2018 1. Map as of May 7, 2019 2. As of Dec. 31, 2018

System Details

Pipeline Miles 3,000 Horsepower of Compression 142,900 Processing Plants 1 Processing Capacity (Bcf/d) 0.06 NGLs Produced (MBbl/d) 6.55 Gross Acres of Dedication 1.2 million

• Fee-based contract structures,

including some support from crude oil gathering contracts with minimum volume commitment features

• XTO Energy, Enable’s customer in

the Bakken, has two active rigs1 drilling wells expected to be connected to Enable’s gathering systems

• Crude oil and water gathering system

expansion with XTO Energy under long-term, fee-based agreements will add up to 72,000 bpd of crude oil gathering design capacity, increasing total Williston Basin crude gathering capacity to up to approximately 130,000 bpd

Williston Basin

16

System Map

2

System Details System Highlights

Crude Gathering Pipeline Miles 175 Water Gathering Pipeline Miles 150 Gross Acres of Dedication 0.3 million

Note: Operational data as of Dec. 31, 2018 1. Per Drillinginfo as of April 24, 2019 2. Map as of May 7, 2019

Appendix

Transportation and Storage Segment Overview

18

Note: Map as of May 7, 2019 1. As of Dec. 31, 2018; excludes SESH which is reported as an equity method investment 2. 50/50 joint venture with Enbridge Inc.

EGT

(Enable Gas Transmission, LLC)

MRT

(Enable Mississippi River Transmission, LLC)

SESH

(Southeast Supply Header, LLC)

• Serves utilities, industrial end-users and producers, providing access to Mid-continent supply and other

Northeastern, Mid-continent and Gulf Coast markets through interconnects

• Serves utilities and industrial end-users, providing access to Mid-continent supply and Northeastern

supply through interconnects

• Primarily serves customers that generate electricity for the Florida power market and interconnects to

pipelines serving major Southeast and Northeast markets

• Serves utilities, industrial end-users and producers, including growing Anadarko Basin production

EOIT

(Enable Oklahoma Intrastate Transmission, LLC)

2

100% Derived from Fee-Based Contracts 88% Derived from Firm Contracts

Transportation and Storage Segment

EGT 54% MRT 13% EOIT 21%

EOIT EGT

100% Fee-Based

System Map and Highlights Transportation and Storage Gross Margin1

Enable Gas Transmission (EGT)

19

• 5,900-mile

1 interstate pipeline serving the

Anadarko, Ark-La-Tex and Arkoma Basins

• EGT’s primary customers include local

distribution companies (LDCs), gas producers and electric utilities

• EGT is well-positioned to serve growing

Oklahoma production and market demand

• The CaSE project, a 205,000 Dth/d

natural gas transportation solution for growing Anadarko Basin production, was placed into full service in Q4-18

• n time and under budget
• EGT’s interconnection at Enable’s

Perryville Hub provides the ability to move natural gas between 11 major interstate pipelines and supports the growing market demand in the Southeast and Gulf Coast regions

Pipeline Map

2

Pipeline Highlights

1. As of Dec. 31, 2018 2. Map as of May 7, 2019; operational data as of Dec. 31, 2018

• 5,900 miles
• 6.0 Bcf/d capacity
• 29.0 Bcf storage capacity

Mississippi River Transmission (MRT)

20

• 1,600-mile1 interstate pipeline that
• ffers shippers competitive rates

and is interconnected to diverse supply points

• MRT’s primary customers are

utilities and industrial end users

• Extended transportation capacity

with its largest customer, St. Louis- based Spire Inc.

• Rate case initially filed June 29,

2018, continues to progress. As of

• Jan. 1, 2019, MRT’s proposed rate

increase is being billed to customers subject to refund depending on the outcome of the case

Pipeline Map2 Pipeline Highlights

Select Interconnects Supply Basin/Region EGT Anadarko, Fayetteville and Haynesville Perryville Hub Barnett, Haynesville and Gulf Coast NGPL & Trunkline Marcellus/Utica, Mid-Con and Gulf Coast

1. As of Dec. 31, 2018 2. Map as of May 7, 2019; operational data as of Dec. 31, 2018

• 1,600 miles
• 1.7 Bcf/d capacity
• 31.5 Bcf storage capacity

Enable Oklahoma Intrastate Transmission (EOIT)

21

• Interconnects natural gas supply from the

Anadarko and Arkoma Basins to Enable’s EGT system and 12 third-party natural gas pipelines

1

• Connected to 44 end-user customers,

including 14 natural gas-fired electric generation facilities in Oklahoma

1

• Major customers include Oklahoma

Gas & Electric Company (OG&E), an affiliate of OGE Energy Corp., and Public Service Company of Oklahoma (PSO), an affiliate of American Electric Power Company, Inc.

• The Muskogee Project, a 20-year,

228,000 Dth/d firm transportation service agreement with OG&E went into service in Q4-18

• Well-positioned to serve transportation

needs for growing production in the Anadarko Basin

Pipeline Map

2

Pipeline Highlights

1. As of Dec. 31, 2018 2. Map as of May 7, 2019; operational data as of Dec. 31, 2018

• 2,300 miles
• 2.08 TBtu/d average throughput
• 24.0 Bcf storage capacity

Southeast Supply Header (SESH)

22

• 290-mile

1 interstate natural gas

pipeline that runs from the Perryville Hub in northeastern Louisiana to southwestern Alabama

• 50% joint venture with Enbridge Inc.
• Well-positioned to serve the high-

growth demand markets of the Southeastern US, including electric utilities

• Twenty interconnects with third-party

natural gas pipelines, providing a diversity of supply from Southeast and Northeast markets

1

• Transportation services are typically

provided under firm, fee-based negotiated rate agreements and have a volume-weighted average remaining contract life of 3.8 years

1

Pipeline Map

2

Pipeline Highlights

1. As of Dec. 31, 2018 2. Map as of May 7, 2019; operational data as of Dec. 31, 2018

• 50% JV with Enbridge Inc.
• 290 miles
• 1.09 Bcf/d capacity

Appendix

Appendix

Enable Ownership Structure

24

Note: Structure as of March 31, 2019

Large, Diverse and High-Quality Customer Base

25

Top Customers

Enable’s revenues are strengthened by a diverse, high-quality customer base, including many investment-grade or affiliates of investment-grade companies

(Investment Grade) (Investment Grade) (Investment Grade) (Investment Grade) (Investment Grade)

• Many of our customers rely on us for multiple midstream services across both G&P and T&S
• Loyal customer base through exemplary customer service and reliable project execution

(Investment Grade) (Investment Grade) (Investment Grade) (Investment Grade)*

Note: Standard and Poor’s, Moody’s and Fitch credit ratings from Bloomberg as of May 6, 2019 *Split rated

(Investment Grade)* (Investment Grade) (Investment Grade)*

2019 Outlook

26

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 May 1, 2019

Derivative Activity and Price Sensitivities

27

• 1. 2019 price sensitivities are based on Enable’s current forecast and commodity outlook and hedges as of April 29, 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 April 11, 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 March 31 2019 2018 Gain (Loss) on Derivative Activity ($10) $-

Change in Fair Value of Derivatives ($12) ($2) Realized Gain on Derivatives $2 $2

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

Commodity 2019 2020 Natural Gas (NYMEX) Exposure Hedged (%) 58% 6% Average Hedge Price ($/MMBtu) $2.86 $3.12 Natural Gas Basis (PEPL / EGTE) Exposure Hedged (%) 49% 27% Average Hedge Price ($/MMBtu) $(0.56) $(0.41) Crude4 Exposure Hedged (%) 67% 23% Average Hedge Price ($/Bbl) $59.87 $64.17 Propane Exposure Hedged (%) 55% 11% Average Hedge Price ($/gal) $0.73 $0.80 Normal Butane Exposure Hedged (%) 26% 0% Average Hedge Price ($/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

($5) ($3) $5 $3 ($5) ($3) $5 $3

Enable Unit Price Appreciation Potential

28

Source: Bloomberg market data and peer mean consensus estimates as of May 8, 2019

• 1. Based on midpoint of Enable’s 2019 Outlook
• 2. Adjustments represents Cash & Equivalents of $18, less Preferred $362, less Minority Interest $38, less Total Debt $4,394
• 3. Annualized common unit distribution of $0.318 per unit
• 4. ENBL unit price as of May 8, 2019
• 5. Median analyst price target from analysts listed on Enable’s Investor Relations website as of May 8, 2019
• 6. LP Units outstanding as of April 12, 2019

EV / EBITDA +31% Potential Uplift Analyst Price Target +23% Potential Uplift Distribution Yield +13% Potential Uplift

$ in Millions

Current ENBL Unit Price EBITDA Multiple Uplift Potential Unit Price Uplift

2019 Adjusted EBITDA1 $1,135 $0 $1,135 EBITDA Multiple 9.5x 1.6x 11.1x Implied Total Enterprise Value $10,770 $1,828 $12,599 Adjustments2 ($4,776) $0 ($4,776) Implied Common Equity Value $5,994 $1,828 $7,823 LP Units Outstanding6 435.1 435.1 Implied Unit Price $13.78 $17.98 $ in Millions

Annualized Distribution3 2019 Distribution Yield Potential Unit Price

ENBL Distribution at ENBL Yield $1.27 9.2% $13.78 ENBL Distribution at Peer Average Yield $1.27 8.2% $15.56

$ in Millions

Current ENBL Unit Price4 Analyst Price Target5

Unit Price $13.78 $17.00

Consolidated Statements of Income

29

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

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

Revenues (including revenues from affiliates): Product sales $ 2,106 $ 1,653 $ 1,172 Service revenue 1,325 1,150 1,100 Total Revenues 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) 1,819 1,381 1,017 Operation and maintenance 388 369 367 General and administrative 113 95 98 Depreciation and amortization 398 366 338 Impairments — — 9 Taxes other than income tax 65 64 58 Total Cost and Expenses 2,783 2,275 1,887 Operating Income 648 528 385 Other Income (Expense): Interest expense (152) (120) (99) Equity in earnings of equity method affiliate 26 28 28 Other, net — — — Total Other Expense (126) (92) (71) Income Before Income Tax 522 436 314 Income tax expense (1) (1) 1 Net Income $ 523 $ 437 $ 313 Less: Net income attributable to noncontrolling interest 2 1 1 Net Income Attributable to Limited Partners $ 521 $ 436 $ 312 Less: Series A Preferred Unit distributions 36 36 22 Net Income Attributable to Common and Subordinated Units (1) $ 485 $ 400 $ 290 Basic earnings per unit Common units $ 1.12 $ 0.92 $ 0.69 Subordinated units (1) $ — $ 0.93 $ 0.68 Diluted earnings per unit Common units $ 1.11 $ 0.92 $ 0.69 Subordinated units (1) $ — $ 0.93 $ 0.68

Non-GAAP Reconciliations

30

Year Ended December 31, 2018 2017 2016

(In millions) Reconciliation of Gross margin to Total Revenues: Consolidated Product sales $ 2,106 $ 1,653 $ 1,172 Service revenue 1,325 1,150 1,100 Total Revenues 3,431 2,803 2,272 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 1,819 1,381 1,017 Gross margin $ 1,612 $ 1,422 $ 1,255 Reportable Segments Gathering and Processing Product sales $ 2,016 $ 1,538 $ 1,081 Service revenue 802 632 559 Total Revenues 2,818 2,170 1,640 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 1,741 1,285 915 Gross margin $ 1,077 $ 885 $ 725 Transportation and Storage Product sales $ 625 $ 621 $ 479 Service revenue 537 525 545 Total Revenues 1,162 1,146 1,024 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 628 604 492 Gross margin $ 534 $ 542 $ 532

Non-GAAP Reconciliations Continued

31

1. Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies 2. This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the years- ended December 31, 2018 and 2017. The year-ended December 31, 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 3. 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 4. See below for a reconciliation of Adjusted interest expense to Interest expense 5. Represents cash distributions declared for common and subordinated units

• utstanding as of each respective
• period. Amounts for 2018 reflect

estimated cash distributions for common units outstanding for the quarter ended December 31, 2018. All

• utstanding subordinated units

converted into common units on a one- for-one basis on August 30, 2017

Year Ended December 31, 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 $ 521 $ 436 $ 312 Depreciation and amortization expense 398 366 338 Interest expense, net of interest income 152 120 99 Income tax expense (1) (1) 1 Distributions received from equity method affiliate in excess of equity earnings 7 5 15 Non-cash equity-based compensation 16 15 13 Change in fair value of derivatives (26) (28) 60 Other non-cash losses (1) 7 11 26 Impairments — — 9 Adjusted EBITDA $ 1,074 $ 924 $ 873 Series A Preferred Unit distributions (2) (36) (36) (31) Distributions for phantom and performance units (3) (5) (2) — Adjusted interest expense (4) (159) (123) (103) Maintenance capital expenditures (114) (101) (101) Current income taxes — (2) 1 DCF $ 760 $ 660 $ 639 Distributions related to common and subordinated unitholders (5) $ 552 $ 551 $ 539 Distribution coverage ratio 1.38 1.20 1.18

Non-GAAP Reconciliations Continued

32

• 1. Other non-cash items include amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies

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

Reconciliation of Adjusted EBITDA to net cash provided by

• perating activities:

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

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

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

2019 Forward Looking Non-GAAP Reconciliation

33

• 1. 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 $0 - ($5) Adjusted EBITDA $1,090 - $1,180 Series A Preferred Unit distributions (1) $36 Adjusted interest expense $195 - $215 Maintenance capital expenditures $105 - $125 Other $5 - $6 DCF $740 - $810

2019 Forward Looking Non-GAAP Reconciliation Continued

34 *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