Enable Midstream Partners, LPFourth Quarter Investor Presentation | December 2020

Some of the information in this presentation may contain forward-looking statements. Forward-looking statements give our current expectations and

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 anticipated financial and operational performance, including our

2020 outlook presented in our first quarter 2020 financial results press release dated May 6, 2020, as updated by this presentation. In particular, our

statements with respect to continuity plans and preparedness measures we have implemented in response to the novel coronavirus (COVID-19)

pandemic and its expected impact on our business, operations, earnings and results are forward-looking statements. 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, our Quarterly Report on Form 10-Q for the three months ended March

31, 2020 (March 31 Quarterly Report), and our Annual Report on Form 10-K for the year ended Dec. 31, 2019 (Annual Report). Those risk factors and

other factors noted throughout this presentation and in our March 31 Quarterly Report and 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.

Any forward-looking statements speak only as of the date on which such statement is made, and we undertake no obligation to correct or update any

forward-looking statement, whether as a result of new information or otherwise, except as required by applicable law.

Forward-looking Statements

2

Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow (DCF) and Distribution coverage ratio are not financial measures

presented in accordance with GAAP. Enable has included these non-GAAP financial measures in this presentation based on information in its

consolidated financial statements.

Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are supplemental financial measures that management

and external users of Enable’s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:

• Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to

capital structure or historical cost basis;

• The ability of Enable’s assets to generate sufficient cash flow to make distributions to its partners;

• Enable’s ability to incur and service debt and fund capital expenditures; and

• The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

This presentation includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable to limited partners,

Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense, the most directly comparable GAAP

financial measures, as applicable, for each of the periods indicated. Distribution coverage ratio is a financial performance measure used by management

to reflect the relationship between Enable's financial operating performance and cash distributions. Enable believes that the presentation of Gross margin,

Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio provides information useful to investors in assessing its financial

condition and results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not be

considered as alternatives to net income, operating income, revenue, cash flow from operating activities, interest expense or any other measure of

financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution

coverage ratio have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP

measures. Additionally, because Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio may be defined

differently by other companies in Enable’s industry, Enable’s definitions of these measures may not be comparable to similarly titled measures of other

companies, thereby diminishing their utility.

Non-GAAP Financial Measures

3

Enable Midstream Overview

Segment Overview

Appendix

Contents

4

Enable Midstream Overview

• Fully integrated midstream platform serves as a critical link between production and downstream markets

• Long-term relationships with large-cap producers, LDCs and electric utilities, many of whom are investment-grade

• Transportation and storage segment is anchored by firm contracts with high-quality customers, providing stability during volatile market

environments

• Over the long term, Enable is well-positioned from both a producer operating cost and wellhead pricing perspective, with Enable providing

unique markets for production and many producers holding downstream

capacity commitments

• Enable continues to work with both producers and customers representing end markets to facilitate competitive market solutions

Enable Benefits from a Diversified Asset Portfolio

6Note: Map as of Nov. 10, 2020

Business Highlights

7

• As of Sept. 1, 2020, all wells that were shut-in due to depressed commodity prices have been brought back

online

• Recently received the Federal Energy Regulatory Commission’s (FERC) Environmental Assessment for the

Gulf Run Pipeline, a key milestone for the project

• Released Enable’s inaugural sustainability report, highlighting the partnership’s commitment to transparency

and sustainable business practices

• COVID-19 safety protocols remain in place; continue to monitor local, state and federal guidelines and

recommendations from health organizations to ensure the

safety of our employees, customers and communities

• Continue to benefit from significant scale, diversified assets, integrated systems, unique market solutions and a

strong base of firm, demand-driven transportation and

storage contracts

2020F DCF 2020F Expansion Capital Distributions

Financial Highlights

8

1. 2020 outlook expectations are as of Nov. 4, 2020 and are not being updated as of the time of this presentation

2. Reference is to outlook ranges provided May 6, 2020

3. 2020 year-to-date through Sept. 30, 2020

4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix

5. Third quarter 2020 distribution annualized

$585 - $645

$288

• November 4th guidance1 provided, stated that we expected to

achieve the upper half of the projected ranges of the 2020

outlook2 for Adjusted EBITDA and DCF and that, excluding the

third quarter 2020 non-cash impairment recognized for

Enable’s SESH joint venture, Enable would have expected to

achieve the upper half of the anticipated range of its 2020

outlook2 for net income

• Business performance and actions taken in response to the

industry downturn earlier this year have resulted in DCF

exceeding distributions by $293 million3 and total debt levels

decreasing by $94 million3

• Progress on cost-reduction initiatives includes annualized

savings of $21 million from workforce reductions, $14 million

from rental equipment turnback and $2 million from processing

plant optimization

• Remain focused on capital discipline

• Have experienced no meaningful credit losses to date

On track to achieve capital and cost reduction targets

announced in April 2020 and committed to further

action, as needed, based on market conditions

2,4

Significant excess cash flow to fund expansion

capital expenditures and reduce debt

$105 - $145

52

Gulf Run Pipeline Project

9

• The Gulf Run Pipeline project, backed by a 20-year commitment for 1.1 Bcf/d with cornerstone shipper Golden

Pass LNG, will provide access to some of the most prolific

natural gas producing regions in the U.S.

• On Oct. 29, 2020, FERC issued the Environmental Assessment, and the deadline for other agencies to act on a

request for federal authorization for the project is Jan. 27,

2021

• Anticipate finalizing the project scope and financing plans in the coming months

• Expect to place project into service in late 2022, subject to FERC approval

PROJECT

ANNOUNCEMENT

2018

OPEN

SEASONSURVEY

WORK

FERC

PRE-FILING

PUBLIC

OPEN HOUSES

FERC SCOPING

MEETINGS

FERC 7(C)

FILING

FERC

APPROVAL

BEGIN

CONSTRUCTION

PROJECT

COMPLETED

GOLDEN

PASS FID

2019

2020

2021 2022

Note: Map as of Nov. 10, 2020

• Segment anchored by large, investment-grade utilities

• Contracted or extended nearly 1,450,000 Dth/d of firm, fee-based transportation capacity in 2020 at an average volume-weighted contract life

of over five years1

• EGT’s MASS project has received all regulatory approvals, and construction of the project has begun; expected to be placed into service in second

quarter 2021

‒ Project is designed to deliver gas from Oklahoma to delivery points with access to emerging Gulf Coast markets and growing demand markets in

the Southeast and is underpinned by a firm, five-year commitment for

100,000 Dth/d

• MRT’s Southbound Expansion project is now in service and is backed by a firm, five-year commitment for 80,000 Dth/d

• Despite recent contract expirations, the SESH pipeline remains a critical artery to serve utility markets in the Southeast

Transportation and Storage Highlights

10

1. 2020 year-to-date contracting through Sept. 30, 2020

• As of Sept. 1, 2020, all wells that were shut-in due to depressed commodity prices have been brought back online

‒ No noticeable production performance degradation from these wells

• Producers remain active on Enable’s gathering footprint with six rigs1

currently drilling wells expected to be connected to Enable’s gathering

systems

• Enable’s customers have approximately 100 drilled but uncompleted2

(DUC) wells behind the Anadarko Basin system and approximately 75

DUC2 wells behind the Williston Basin system, providing an inventory of

wells producers can complete without investing additional drilling capital

• Enable Oklahoma Crude Services, LLC recently completed an extension into McClain County, increasing the system’s reach and ability to add new

customers

• Natural gas forward curves have increased by nearly 30%3 for 2021, supporting continued producer activity in the Haynesville Shale

• Recently completed a connection to a seven-well pad for a new Williston Basin customer

Gathering and Processing Highlights

11

1. Rigs per Enverus as of Oct. 28, 2020; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering systems

2. Represents DUCs expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering system as of Sept. 30, 2020

3. Average percent change of NYMEX forward curves for January 2021 through December 2021, when comparing Jan. 1, 2020, strip prices to Nov. 1, 2020, strip prices

Dedicated Partner

Focus on Sustainability

12

• Enable is making a difference in species conservation,

demonstrated by participation in the American

Burying Beetle Oil & Gas Industry Conservation

Plan, a species that was recently downlisted from

endangered to threatened status

• Enable’s award-winning integrated vegetation

management program along our rights-of-ways, which

uses a variety of techniques to control incompatible and

invasive plant species while promoting the growth of

compatible herbaceous, native plant species that may

also benefit wildlife and pollinator species

• Pipeline inspection program that inspected almost

twice the miles of pipelines in 2019 as required by

current regulations

• Enable has made a series of commitments intended to

minimize methane emissions across Enable’s

operations through INGAA’s Methane Emissions

Commitments

Enable is

committed to

operating

honestly, fairly,

safely and

ethically

Enable released its inaugural sustainability report, highlighting the partnership’s

commitment to transparency and sustainable business practices

• Community partnerships, including Enable’s

Safety Partner Program honoring first

responders, a program to build or refurbish

community basketball courts and a program to

support STEM-focused educational initiatives

• Over 22,000 employee volunteer hours in

2019, including over 15,000 company-paid hours

• A comprehensive contractor safety initiative,

which contributed to a reduction of reported

contractor incidents from 22 in 2015 to three in

2019

Environmental Steward

The full report is available at https://enablemidstream.com/sustainability

https://enablemidstream.com/sustainability

Segment Overview

Transportation and Storage Segment

14

EOIT

MRT

SESH

EGT

EGT (Enable Gas Transmission, LLC)

MRT (Enable Mississippi River Transmission, LLC) SESH2 (Southeast Supply Header, LLC)

EOIT (Enable Oklahoma Intrastate Transmission, 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

100% Derived from

Fee-Based Contracts

93% Derived from

Firm Contracts

100%

Fee-Based

EGT 59%

MRT 11%

EOIT 23%

Note: Map as of Nov. 10, 2020

1. As of Dec. 31, 2019; excludes SESH which is reported as an equity method investment

2. 50/50 joint venture with Enbridge Inc.

Transportation and Storage Highlights Transportation and Storage Gross Margin1

Arkoma Basin Williston Basin

Anadarko Basin

Gathering and Processing Segment

15

Our operations primarily serve the Woodford

Shale play located in Oklahoma and the

Fayetteville Shale play located in Arkansas.

Our Arkoma Basin gathering and processing

operations serve both rich and lean gas

production from approximately 80 producers1.

Contracts are primarily fee-based contracts

with significant support from MVCs, which have

a weighted average remaining term of 4.7

years1.

We have operations in the Bakken Shale that

are located in North Dakota. The focus of our

operations in the Williston Basin is the

gathering of crude oil and produced water for

XTO Energy Inc., an affiliate of ExxonMobil

Corporation, with pipeline gathering systems in

Dunn, McKenzie, Williams and Mountrail

counties of North Dakota.

Natural Gas - We have natural gas gathering

and processing operations in the SCOOP,

STACK, Granite Wash, Cleveland, Marmaton,

Tonkawa, Cana Woodford and Mississippi Lime

plays. Enable serves over 200 producers1 in

the Anadarko Basin and has secured 5.0

million gross acres1 of dedication under long-

term, fee-based contracts.

Crude Oil and Condensate - Our operations in

the Anadarko Basin include gathering of crude

oil and condensate from producers in the

SCOOP, STACK and Merge plays.

We have gathering and processing operations

in the Ark-La-Tex Basin located in Arkansas,

Louisiana and Texas. Our Ark-La-Tex gathering

and processing operations primarily serve the

Haynesville, Cotton Valley and the lower

Bossier plays. We serve approximately 90

producers1 in the Ark-La-Tex Basin where our

gathering and processing operations provide

service for both rich and lean gas production.

The scale of Enable’s Ark-La-Tex Basin assets

allows us to be well-positioned to supply

demand growth from LNG exports.

Substantial size and scale in prominent basins

underpinned with favorable contract structures

• 15 Processing Plants with ~2.6 Bcf/d of processing capacity1

• 8.2 million gross acres dedicated under gathering agreements with a volume-weighted average remaining term of 4.3 years1 for natural gas and

11.8 years1 for crude oil and condensate

• 2019 Gathering and Processing segment gross margin was 80% fee-based1

1. As of Dec. 31, 2019

Gathering and Processing Highlights Basin Highlights

Ark-La-Tex Basin

Appendix

Enable Ownership Structure

17Note: Structure as of Sept. 30, 2020

Large, Diverse and High-Quality Customer Base

Enable’s revenues are

strengthened by a diverse,

high-quality customer base,

including many investment-

grade or affiliates of

investment-grade companies

• 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)

18Note: Standard and Poor’s, Moody’s and Fitch credit ratings from Bloomberg as of Nov. 4, 2020

Investment grade rated indicates that the company has an investment-grade rating from Standard and Poor’s, Moody’s or Fitch

1. As of Dec.31, 2019

(Investment Grade) (Investment Grade)

(Investment Grade) (Investment Grade)

(Investment Grade) (Investment Grade)

(Investment Grade) (Investment Grade)

(Investment Grade) (Investment Grade)

Top Customers1

Financial Results

191. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix

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

Three Months Ended Sept. 30 Nine Months Ended Sept. 30

$ in millions, except per-unit and ratio data 2020 2019 Change 2020 2019 Change

Total Revenues $596 $699 ($103) $1,759 $2,229 ($470)

Gross Margin1 $346 $436 ($90) $1,106 $1,271 ($165)

Net Income (Loss) Attributable to Limited Partners ($164) $132 ($296) ($8) $378 ($386)

Net Income (Loss) Attributable to Common Units ($173) $123 ($296) ($35) $351 ($386)

Net Cash provided by Operating Activities $232 $264 ($32) $543 $691 ($148)

Adjusted EBITDA1

$229 $295 ($66) $739 $873 ($134)

Distributable Cash Flow1

$147 $202 ($55) $509 $607 ($98)

Distribution Coverage Ratio1,2

2.04x 1.40x 0.64x 2.36x 1.42x 0.94x

Cash Distribution per Common Unit $0.16525 $0.3305 ($0.16525)

Cash Distribution per Series A Preferred Unit $0.625 $0.625 $0

Operational Performance Overview

4.622.54

Natural gas gathered

volumes decreased for

third quarter 2020

compared to third quarter

2019 primarily as a result

of lower gathered volumes

across all basins, inclusive

of continued producer

shut-ins in the Anadarko

Basin that ended in the

third quarter

Natural gas processed

volumes decreased for third

quarter 2020 compared to

third quarter 2019 as a

result of lower processed

volumes across all basins

Crude oil and

condensate gathered

volumes increased for

third quarter 2020

compared to third quarter

2019 primarily as a result

of higher production in

the Anadarko Basin,

partially offset by lower

production in the

Williston Basin

Transported volumes

decreased for third quarter

2020 compared to third

quarter 2019 primarily as a

result of decreased

production in the Anadarko

Basin, which contributed to

lower utilization on both

interstate and intrastate

pipelines

20

8.9% Decrease

4.47 4.07

Q3 2019 Q3 2020

TBtu/d

17.3% Decrease

2.49

2.06

Q3 2019 Q3 2020

TBtu/d

MBbl/d

3.8% Increase

132.99 138.02

Q3 2019 Q3 2020

19.9% Decrease

5.97

4.78

Q3 2019 Q3 2020

TBtu/d

Natural Gas Gathered Volumes

Natural Gas Processed Volumes

Crude Oil and Condensate Gathered Volumes

Transported Volumes

Gathering and Processing Operational Results

21

Three Months Ended Sept. 30 Nine Months Ended Sept. 30

Operational Results 2020 2019 Change 2020 2019 Change

Gathered Volumes (TBtu/d) 1.94 2.27 (0.33) 2.04 2.32 (0.28)

Processed Volumes (TBtu/d)1 1.76 2.04 (0.28) 1.85 2.07 (0.22)

NGLs Produced (MBbl/d)1,2 120.80 103.53 17.27 109.29 111.99 (2.70)

Crude Oil and Condensate Gathered Volumes (MBbl/d) 104.93 91.58 13.35 93.65 82.75 10.90

Gathered Volumes (TBtu/d) 0.41 0.46 (0.05) 0.42 0.48 (0.06)

Processed Volumes (TBtu/d) 1 0.08 0.10 (0.02) 0.08 0.10 (0.02)

NGLs Produced (MBbl/d) 1,2 3.94 4.42 (0. 48) 3.96 5.89 (1.93)

Gathered Volumes (TBtu/d) 1.72 1.74 (0.02) 1.79 1.74 0.05

Processed Volumes (TBtu/d) 0.22 0.35 (0.13) 0.25 0.35 (0.10)

NGLs Produced (MBbl/d) 2 8.37 9.83 (1.46) 9.04 10.74 (1.70)

Crude Oil Gathered Volumes (MBbl/d) 33.09 41.41 (8.32) 27.73 37.42 (9.69)

Financial Results ($ in millions)

To

tal

G&

P

Total Revenues3 $463 $542 ($79) $1,331 $1,759 ($428)

Gross Margin3,4 $219 $304 ($85) $700 $864 ($164)

Operation & Maintenance and G&A Expenses3 $77 $79 $2 $250 $238 ($12)

Depreciation and Amortization $75 $77 $2 $223 $229 $6

Impairment - - - $28 - ($28)

Taxes other than Income Tax $10 $10 - $32 $31 ($1)

Operating Income $57 $138 ($81) $167 $366 ($199)

1. Includes volumes under third-party processing

arrangements

2. Excludes condensate

3. Before eliminations upon consolidation

4. Non-GAAP financial measures are reconciled to the

nearest GAAP financial measures in the Appendix

Arkoma Basin

Ark-La-Tex Basin

Anadarko Basin

Williston Basin

Transportation and Storage Segment Results

221. Before eliminations upon consolidation2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix

Operational Results Three Months Ended Sept. 30 Nine Months Ended Sept. 30

2020 2019 Change 2020 2019 Change

Transported Volumes (Tbtu/d) 4.78 5.97 (1.19) 5.58 6.22 (0.64)

Interstate Firm Contracted Capacity (Bcf/d) 5.73 6.02 (0.29) 6.00 6.31 (0.31)

Intrastate Average Deliveries (TBtu/d) 1.74 2.10 (0.36) 1.83 2.16 (0.33)

Financial Results ($ in millions) Three Months Ended Sept. 30 Nine Months Ended Sept. 30

Total Revenues1 $205 $234 ($29) $622 $802 ($180)

Gross Margin1,2 $127 $132 ($5) $407 $408 ($1)

Operation & Maintenance and G&A Expenses1 $47 $57 $10 $137 $152 $15

Depreciation and Amortization $30 $31 $1 $91 $94 $3

Taxes other than Income Tax $7 $7 - $20 $21 $1

Operating Income $43 $37 $6 $159 $141 $18

Consolidated Statements of Income

23

Three Months Ended September 30,

Nine Months Ended September 30,

2020 2019 2020 2019

(In millions, except per unit data)

Revenues (including revenues from affiliates):

Product sales $ 280 $ 320 $ 764 $ 1,156

Service revenue 316 379 995 1,073

Total Revenues 596 699 1,759 2,229

Cost and Expenses (including expenses from affiliates):

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 250 263 653 958

Operation and maintenance 96 105 313 307

General and administrative 28 31 73 82

Depreciation and amortization 105 108 314 323

Impairments of property, plant and equipment and goodwill — — 28 —

Taxes other than income tax 17 17 52 52

Total Cost and Expenses 496 524 1,433 1,722

Operating Income 100 175 326 507

Other Income (Expense):

Interest expense (43) (48) (136) (142)

Equity in earnings (loss) of equity method affiliate, net (222) 5 (211) 12

Other, net 2 1 7 2

Total Other Expense (263) (42) (340) (128)

Income Before Income Tax (163) 133 (14) 379

Income tax benefit — — — (1)

Net Income (Loss) $ (163) $ 133 $ (14) $ 380

Less: Net income (loss) attributable to noncontrolling interest 1 1 (6) 2

Net Income (Loss) Attributable to Limited Partners $ (164) $ 132 $ (8) $ 378

Less: Series A Preferred Unit distributions 9 9 27 27

Net Income (Loss) Attributable to Common Units $ (173) $ 123 $ (35) $ 351

Basic earnings (loss) per unit

Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81

Diluted earnings (loss) per unit

Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81

Non-GAAP Reconciliations

24

Three Months Ended September 30,

Nine Months Ended September 30,

2020 2019 2020 2019

(In millions)Reconciliation of Gross margin to Total Revenues:

Consolidated

Product sales $ 280 $ 320 $ 764 $ 1,156

Service revenue 316 379 995 1,073

Total Revenues 596 699 1,759 2,229

Cost of natural gas and natural gas liquids (excluding depreciation and amortization)250 263 653 958

Gross margin $ 346 $ 436 $ 1,106 $ 1,271

Reportable Segments

Gathering and Processing

Product sales $ 271 $ 294 $ 739 $ 1,096

Service revenue 192 248 592 663

Total Revenues 463 542 1,331 1,759

Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 244 238 631 895

Gross margin $ 219 $ 304 $ 700 $ 864

Transportation and Storage

Product sales $ 79 $ 100 $ 213 $ 381

Service revenue 126 134 409 421

Total Revenues 205 234 622 802

Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 78 102 215 394

Gross margin $ 127 $ 132 $ 407 $ 408

Non-GAAP Reconciliations Continued

25

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 write-downs and net loss on sale and retirement

of assets

3. Represents the quarterly cash distributions on the Series A Preferred Units

declared for the three and nine months ended Sept. 30, 2020, and 2019. 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 the next slide 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 2020 reflect estimated cash distributions for

common units outstanding for the quarter ended Sept. 30, 2020

7. Distribution coverage ratio is computed by dividing DCF by Distributions related

to common unitholders

Three Months Ended September 30,

Nine Months Ended September 30,

2020 2019 2020 2019

(In millions, except Distribution coverage ratio)

Reconciliation of Adjusted EBITDA and DCF to net income (loss) attributable to limited partners and calculation of Distribution coverage ratio:

Net income (loss) attributable to limited partners $ (164) $ 132 $ (8) $ 378

Depreciation and amortization expense 105 108 314 323

Interest expense, net of interest income 43 48 135 141

Income tax benefit — — — (1)

Distributions received from equity method affiliate in excess of equity earnings 1 (1) 9 8

Impairment of equity method affiliate investment 225 — 225 —

Non-cash equity-based compensation 3 4 10 13

Change in fair value of derivatives (1) 15 2 17 3

Other non-cash losses (2) 1 2 23 9

Impairments of property, plant and equipment and goodwill — — 28 —

Gain on extinguishment of debt — — (5) —

Noncontrolling Interest Share of Adjusted EBITDA — — (9) (1)

Adjusted EBITDA $ 229 $ 295 $ 739 $ 873

Series A Preferred Unit distributions (3) (9) (9) (27) (27)

Distributions for phantom and performance units (4) — (1) (1) (10)

Adjusted interest expense (5) (42) (47) (134) (143)

Maintenance capital expenditures (31) (36) (69) (86)

Current income taxes — — 1 —

DCF $ 147 $ 202 $ 509 $ 607

Distributions related to common unitholders (6) $ 72 $ 144 $ 216 $ 426

Distribution coverage ratio (7) 2.04 1.40 2.36 1.42

Non-GAAP Reconciliations Continued

261. Other non-cash items includes write-downs of assets2. 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,

2020 2019 2020 2019

(In millions)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:

Net cash provided by operating activities $ 232 $ 264 $ 543 $ 691

Interest expense, net of interest income 43 48 135 141Noncontrolling interest share of cash provided by operating

activities (1) (1) (3) (2)

Current income taxes — — 1 —

Other non-cash items (1) (2) — — 4

Proceeds from insurance 1 — 1 —

Changes in operating working capital which (provided) used cash:

Accounts receivable 3 41 (27) (16)

Accounts payable (24) (2) 46 110

Other, including changes in noncurrent assets and liabilities (39) (56) 17 (66)

Return of investment in equity method affiliate 1 (1) 9 8

Change in fair value of derivatives (2) 15 2 17 3

Adjusted EBITDA $ 229 $ 295 $ 739 $ 873

Three Months Ended September 30,

Nine Months Ended September 30,

2020 2019 2020 2019

(In millions)

Reconciliation of Adjusted interest expense to Interest expense:

Interest expense $ 43 $ 48 $ 136 $ 142

Interest income — — (1) (1)

Amortization of premium on long-term debt — 1 1 4

Capitalized interest on expansion capital 1 — 2 1

Amortization of debt expense and discount (2) (2) (4) (3)

Adjusted interest expense $ 42 $ 47 $ 134 $ 143

2020 Forward-Looking Non-GAAP Reconciliations

271. Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common units outlook; excludes non-cash other than temporary impairment on Enable’s investment in Southeast

Supply Header, LLC

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) $231 – $271

Depreciation and amortization expense $415 – $425

Interest expense, net of interest income $174 – $184

Income tax (benefit) expense $0

Distributions received from equity method affiliate in excess of equity

earnings$5 – $11

Non-cash equity based compensation $19

Change in fair value of derivatives (2) $10

Other non-cash losses $23

Impairments $28

Noncontrolling Interest Share of Adjusted EBITDA ($8)

Adjusted EBITDA $900 – $960

Series A Preferred Unit distributions (3) ($36)

Adjusted interest expense ($170) – ($180)

Maintenance capital expenditures ($95) – ($105)

Other ($4)

DCF $585 – $645