Enable Midstream Partners, LP First Quarter 2017 Conference Call - - PowerPoint PPT Presentation

Enable Midstream Partners, LP

First Quarter 2017 Conference Call

May 3, 2017

Forward-looking Statements

This presentation and the oral statements made in connection herewith may contain “forward-looking statements” within the meaning of the securities laws. All statements, other than statements of historical fact, regarding Enable Midstream Partners’ (“Enable”) strategy, future operations, financial position, estimated revenues, projected costs, prospects, plans and objectives of management are forward-looking statements. These statements often include the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast” and similar expressions and are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Enable’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Enable assumes no obligation to and does not intend to update any forward-looking statements included herein. When considering forward-looking statements, which include statements regarding future commodity prices, future capital expenditures and our financial and operational outlook for 2017, among others, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” and elsewhere in our SEC filings. Enable cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many

• f which are beyond its control, incident to the ownership, operation and development of natural gas and crude oil

infrastructure assets. These risks include, but are not limited to, contract renewal risk, commodity price risk, environmental risks, operating risks, regulatory changes and the other risks described under “Risk Factors” and elsewhere in our SEC filings. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Enable’s actual results and plans could differ materially from those expressed in any forward-looking statements.

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Non-GAAP Financial Measures

3

Enable has included the non-GAAP financial measures Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow and distribution coverage ratio in this presentation based on information in its condensed 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, its definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Enable Highlights

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• Announcing Project Wildcat, providing premium

market outlets for growing production out of the SCOOP and STACK plays in the Anadarko Basin and adding 400 million cubic feet per day (MMcf/d) of processing capacity

• Signed a 10-year, 205 MMcf/d firm natural gas

transportation agreement with Newfield Exploration Company to transport Newfield’s production out of the Anadarko Basin

• Increased total revenues, net income

attributable to limited partners and to common and subordinated units, gross margin and Adjusted EBITDA for first quarter 2017 compared to first quarter 2016

• Increased per-day natural gas gathered,

processed and transported volumes for first quarter 2017 compared to first quarter 2016

• Quarterly cash distributions of $0.318 per unit
• n all outstanding common and subordinated units

and $0.625 on all Series A Preferred Units

Creative and Capital Efficient Anadarko Basin Market Solutions

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• Previously announced 10-year, 205 MMcf/d firm natural gas

transportation agreement with Newfield Exploration Company

• Provides Newfield with a timely, cost-effective and flexible

natural gas transportation solution out of the Anadarko Basin with access to preferred markets, including Bennington, Oklahoma, and Enable’s Perryville Hub

• Initial capacity of 45 MMcf/d expected to start in early 2018,

growing to 205 MMcf/d by fourth quarter 2018

Cana & STACK Expansion (CaSE) Project Wildcat

• Enable has entered into an agreement to deliver

approximately 400 MMcf/d of rich natural gas from the Anadarko Basin to north Texas, providing new market outlets for growing Anadarko Basin production.

• Will provide access to the Texas intrastate natural gas

markets, including the Tolar Hub, by Enable contracting with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of firm processing capacity at the Godley Plant in Johnson County, Texas

• Estimated to be in service by the end of the second quarter
• f 2018

+600MMcf/d

New market solutions announced in 2017

+400MMcf/d

Additional processing capacity for SCOOP and STACK production

2018 DCF

Expected to be accretive to distributable cash flow

Note: Processing capacity per Bentek as of April 3, 2017; represents processing capacity in designated SCOOP and STACK counties where SCOOP is designated as Caddo, Carter, Garvin, Grady, McClain and Stephens counties of Oklahoma and STACK is designated as Blaine, Canadian, Custer, Dewey, Kingfisher, Major and Woodward counties of Oklahoma 1. Represents the 400 MMcf/d of processing capacity provided at the Godley Plant in Johnson County, Texas, for incremental gathered volumes in the Anadarko Basin; capacity estimated to be available by the end of Q2-2018

1

Over 1 Bcf/d of Recently Contracted Market Solutions for Growing SCOOP and STACK Production

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Capital-Efficient Expansion Projects Provide Critical Access to Premium Markets

Tolar Hub Bennington Perryville Hub TGT Helena

Texas Markets

~400

MMcf/d

Bennington & Southeast Markets

~600

MMcf/d CaSE Project1

In-service Expected Q4-2018

Project Wildcat

In-service Expected Q2-2018

Line AD Expansion

In-service Q2-2017

Bradley Lateral

In-service Q4-2015

Note: Map as of April 24, 2017; Completion of the announced Wildhorse plant has been deferred 1. Initial capacity of 45 MMcf/d in early 2018, growing to full 205 MMcf/d by Q4-2018

1.57 1.611.62 1.661.67 1.75

Increases Processing Capacity for Anadarko Basin Production1

~2.25

Bcf/d

1.85 Bcf/d 2.25 Bcf/d

2016 Projected 2018

Project Wildcat Positions Enable for Further Anadarko Basin Growth

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Gathered Volumes

TBtu/d

22%

Increase

Note: Map as of April 24, 2017; Completion of the announced Wildhorse plant has been deferred 1. Includes the 400 MMcf/d of processing capacity provided at the Godley Plant in Johnson County, Texas, for incremental gathered volumes in the Anadarko Basin; capacity estimated to be available by the end of Q2-2018

Processed Volumes

TBtu/d 1.39 1.41 1.44 1.50 1.52 1.54

+11.5% +10.8%

1

Financial Results

5.11 5.48 Q1-16 Q1-17 3.05 3.29 Q1-16 Q1-17

Continued Strong Operational Performance

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Active Rigs on Enable’s Footprint1 Transported Volumes Natural Gas Gathered Volumes Natural Gas Processed Volumes

TBtu/d TBtu/d TBtu/d

7.2%

Increase

• Sustained rig activity in the Anadarko and Ark-La-Tex Basins contributed to higher volumes across Enable’s gathering and

processing and transportation and storage assets for first quarter 2017 compared to first quarter 2016

• Total natural gas gathered volumes increased for the 5th consecutive quarter as a result of higher gathered volumes in the

Anadarko and Ark-La-Tex Basins

• Total natural gas processed volumes increased for the 3rd consecutive quarter primarily as a result of higher processed volumes

in the Anadarko Basin

7.9%

Increase

15 5 2 9 1 STACK SCOOP Granite Wash Ark-La-Tex Williston 1.78 1.87 Q1-16 Q1-17

5.1%

Increase

1. Per Drillinginfo as of April 17, 2017

First Quarter 2017 Financial Results

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1. Adjusted EBITDA and DCF are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures in the appendix 2. A non-GAAP measure calculated as DCF divided by distributions related to common and subordinated units 3. The Q1-16 quarterly distribution on the Series A Preferred Units is for a partial period beginning on Feb. 18, 2016, and ending on Mar. 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

In millions, except per unit and ratio data Q1-17 Q1-16 Total Revenues $666 $509 Gross Margin $358 $314 Net Income Attributable to Limited Partners $120 $86 Net income Attributable to Common and Subordinated Units $111 $86 Net Cash provided by Operating Activities $156 $117 Adjusted EBITDA1 $221 $215 Distributable Cash Flow1 $171 $174 Distribution Coverage Ratio2 1.25x 1.30x Cash Distribution per Common and Subordinated Unit $0.318 $0.318 Cash distribution per Series A Preferred Unit3 $0.6250 $0.2917

Key Drivers

Net Income – Common and Subordinated Units Adjusted EBITDA Distributable Cash Flow

• Higher gathering and processing and transportation and storage gross

margin partially offset by:

• Higher depreciation and amortization expense primarily as a result of

additional assets placed in service

• Higher interest expense primarily due to higher interest rates on
• utstanding debt
• Distributions on Series A Preferred Units
• Higher gathering and processing and transportation and storage gross

margin partially offset by:

• Changes in fair value of derivatives
• One-time impact from change from quarterly distributions to monthly

distributions for Southeast Supply Header, LLC (SESH) for Q1-16

• Higher Adjusted interest expense primarily due to higher interest rates on
• utstanding debt
• Distributions on Series A Preferred Units in Q1-17 that were only incurred

for a partial quarter in Q1-16

• Partially offset by higher Adjusted EBITDA

3.81x 3.48x Q1-16 Q1-17

Strong Balance Sheet and Liquidity Position

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• In March, Enable completed an offering of $700 million in aggregate principal amount of 4.400%

senior notes due in 2027

• Enable used the net proceeds from the offering for general partnership purposes, including to repay

amounts outstanding under its revolving credit facility

• Enable’s $1.75 billion Revolving Credit Facility was undrawn as of March 31, 20171

Debt Maturity Schedule2 Total Debt / LTM Adjusted EBITDA

$500 $600 $700 $550 $250 $450 2017 2018 2019 2020 2024 2027 2044

ENBL Sr. Unsecured Notes EOIT Sr. Unsecured Notes Term Loan Facility

1. The Revolving Credit Facility matures on June 18, 2020. As of March 31, 2017, there were no principal advances and $3 million in letters of credit

• utstanding under the $1.75 billion Revolving Credit Facility

2. The Term Loan Facility includes two, one-year extension options

2017 Outlook

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2017 Natural Gas Gathered Volumes (TBtu/d) 3.3 – 3.8 Anadarko 1.7 – 2.0 Arkoma 0.5 – 0.7 Ark-La-Tex 0.9 – 1.3 Natural Gas Processed Volumes (TBtu/d) 1.9 – 2.3 Anadarko 1.6 – 1.9 Arkoma 0.1 – 0.2 Ark-La-Tex 0.1 – 0.3 Crude Oil – Gathered Volumes (MBbl/d) 23.0 – 28.0 Interstate Firm Contracted Capacity (Bcf/d) 6.1 – 6.5

2017 Operational Outlook 2017 Financial Outlook

2017 Outlook: Operational and Financial Outlook Remain Unchanged, Expansion Capital Updated

$ in millions

2017 Net Income Attributable to Common and Subordinated Unit Holders $315 – $385 Interest Expense $114 – $122 Adjusted EBITDA1 $825 – $885 Preferred Equity Distributions2 $36 Adjusted Interest Expense1 $120 – $130 Maintenance Capital $95 – $125 Distributable Cash Flow1 $555 – $605 Distribution Coverage Ratio 1.0x or greater

2017 Expansion Capital Outlook

$ in millions

2017 Gathering and Processing $425 – $515 Transportation and Storage $75 – $85 Total Expansion Capital $500 – $600

Note: 2017 Outlook originally released on November 2, 2016 1. Financial measures are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures on slide 26 and 27 2. Includes the fourth quarter 2017 distribution that will be paid in the first quarter 2018 3. NGL composite based on assumed composition of 45%, 30%, 10%, 5% and 10% for ethane, propane, normal butane, isobutane and natural gasoline, respectively

2017 Price Assumptions

2017 Natural Gas – Henry Hub ($/MMBtu) $3.05 – $3.45 NGLs – Mont Belvieu, Texas ($/gal)3 $0.46 – $0.56 NGLs – Conway, Kansas ($/gal)3 $0.44 – $0.54 Crude Oil – WTI ($Bbl) $48.00 – $58.00

• Updated 2017 Expansion Capital Outlook includes the addition of

Project Wildcat, the addition of the recently announced CaSE project and revised capital projections for other projects

Question and Answer Question & Answer

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Key Highlights

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• Diverse suite of assets that provides tailored and timely solutions from

wellhead to end markets

• Recently announced over 600 MMcf/d of market solutions out of the

Anadarko Basin

• Recently contracted over 1 billion cubic feet per day (Bcf/d) of market

solutions for growing SCOOP and STACK production

• Project Wildcat will add an additional 400 MMcf/d of processing for the

SCOOP and STACK plays, bringing total processing capacity for Anadarko Basin production to over 2.2 Bcf/d by second quarter 20181

• Additional processing capacity positions Enable well for future growth
• pportunities
• Continue to prioritize efficient capital deployment
• High interconnectivity of assets provides ability to customize customer

solutions with minimized incremental capital spend

• Recently announced projects are expected to be accretive to 2018

distributable cash flow once in service Creative New Market Solutions Anadarko Basin Positioned for Growth Efficient Capital Deployment and Accretive Growth

1. Includes the 400 MMcf/d of processing capacity provided at the Godley Plant in Johnson County, Texas, for incremental gathered volumes in the Anadarko Basin; capacity estimated to be available by the end of Q2-2018

Appendix Appendix

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Derivative Activity and Price Sensitivities

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1. Price sensitivities are for the nine months ending December 31, 2017; based on current prices and current hedges 2. The impact of price sensitivities is the same for net income attributable to limited partners and net income attributable to common and subordinated units

Impact to 2017 Net Income (including impact of hedges)2 % Change in Prices

$ in millions

+10%

• 10%

Natural Gas and Ethane $1 ($2) NGLs (excluding ethane) and Condensate $3 ($3) Impact to 2017 Adjusted EBITDA (including impact of hedges) % Change in Prices

$ in millions

+10%

• 10%

Natural Gas and Ethane $2 ($2) NGLs (excluding ethane) and Condensate $4 ($4) Three Months Ended Mar. 31

$ in millions

2017 2016 Gain (Loss) on Derivative Activity $21 $3

Change in Fair Value of Derivatives $24 $(8) Realized Gain (Loss) on Derivative Activity ($3) $11

2017 Price Sensitivities1 2017 Derivative Activity

Gross Margin and Hedging Summary

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1. 2017 gross margin is based on hedges as of April 11, 2017, and Enable’s April 2017 price assumptions; represents gross margin for Q2-17 through Q4-17 2. Table includes 2017 hedges and commodity exposures associated with equity volumes resulting from Enable's Gathering, Processing and Transportation businesses; percentage hedged includes hedges executed through April 14, 2017 for Q2-17 through Q4-17 3. Enable hedges net condensate/natural gasoline exposure with crude

Commodity 2017 Natural Gas

Exposure Hedged (%) 64% Average Hedge Price ($/MMBtu) $2.72

Crude3

Exposure Hedged (%) 67% Average Hedge Price ($/Bbl) $51.32

Propane

Exposure Hedged (%) 65% Average Hedge Price ($/gal) $0.50

53% 32% 8% 7% Firm/MVC Fee-based Other Fee-based Commodity-based Hedged Commodity-based Unhedged

2017 Gross Margin Profile1

~93% fee- based or hedged

2017 Hedging Summary2

Financial Results

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1. Excludes eliminations 2. Gross Margin is a non-GAAP financial measure and is reconciled to the nearest GAAP financial measures on slide 23

Selected Results - $ in millions

Q1-2017 Q1-2016 Key Drivers: Q1-17 vs. Q1-16 Revenue $666 $509 Gathering and Processing1 $491 $333 Increase in NGL sales resulting from higher average NGL prices, an increase in sales of natural gas as a result of higher average natural gas prices, changes in the fair value of condensate and NGL derivatives and an increase in natural gas gathering revenues due to higher fees and gathered volumes in the Anadarko and Ark- La-Tex Basins Transportation and Storage1 $294 $246 Higher natural gas sales associated with higher sales volumes and higher average sales prices and changes in the fair value of natural gas derivatives Gross Margin2 $358 $314 Gathering and Processing1,2 $205 $168 Increase in gathered volumes in the Anadarko and Ark-La-Tex Basins, changes in the fair value of condensate and NGL derivatives, an increase in processing margins resulting from higher average NGL prices and higher processed volumes in the Anadarko Basin, partially offset by a decrease in the imbalance receivable associated with annual fuel rate determination in 2016 Transportation and Storage1,2 $154 $147 Changes in the fair value of natural gas derivatives and an increase in firm transportation margins, partially offset by a decrease in system management activities Operation and Maintenance & General and Administrative Expenses $114 $115 Decrease in allowance for doubtful accounts and reductions in equipment rentals, information technology-related costs and various

• ther operating costs, partially offset by an increase in payroll-

related costs Depreciation and Amortization $88 $81 Additional assets placed in service Taxes other than Income Taxes $16 $15 Higher accrued ad valorem taxes due to additional assets placed into service Interest Expense $27 $23 Higher interest rates on outstanding debt

Financial Results Continued

20

1. Adjusted EBITDA, DCF and Adjusted Interest Expense are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures on slide 24 and 25 2. A non-GAAP measure calculated as DCF divided by distributions related to common and subordinated unitholders

Selected Results - $ in millions

Q1-2017 Q1-2016 Key Drivers: Q1-17 vs. Q1-16 Net Income Attributable to Limited Partners $120 $86 Higher gross margin, partially offset by higher interest expense and higher depreciation and amortization expense Net Income Attributable to Common and Subordinated Units $111 $86 Same drivers as Net Income attributable to limited partners and distributions on the Series A Preferred Units for first quarter 2017 that were not recognized in income for first quarter 2016 Net Cash provided by Operating Activities $156 $117 Increase in net income, partially offset by a decrease related to the timing of cash receipts and disbursements and changes in

• ther working capital assets and liabilities

Adjusted EBITDA1 $221 $215 Higher gross margin, partially offset by changes to fair value of derivatives and higher distributions from equity method affiliates in first quarter 2016 as a result of a change from quarterly distributions to monthly distributions for SESH that occurred in first quarter 2016 Series A Preferred Unit Distribution $9 $4 Distributions on Series A Preferred Units in Q1-17 that were only incurred for a partial quarter in Q1-16 Adjusted Interest Expense1 $27 $23 Higher interest rates on outstanding debt Maintenance Capital $14 $13 Distributable Cash Flow1 $171 $174 Higher Adjusted interest and higher distributions on the Series A Preferred Units, partially offset by higher Adjusted EBITDA Distribution Coverage Ratio2 1.25x 1.30x Expansion Capital $47 $117

Operating Statistics

1. Excludes condensate

21 Q1-2017 Q1-2016 Key Drivers: Q1-17 vs. Q1-16 Gathered Volumes (TBtu/d) 3.29 3.05 Higher gathered volumes in the Anadarko and Ark-La-Tex Basins Natural Gas Processed Volumes (TBtu/d) 1.87 1.78 Higher processed volumes in the Anadarko Basin, partially offset by lower processed volumes in the Ark-La-Tex Basin NGLs Produced (MBbls/d)1 79.76 73.47 Higher NGL production in the Anadarko Basin, partially offset by NGL production declines in the Ark-La-Tex Basin Condensate Sold (MBbls/d) 5.47 6.45 New infrastructure placed into service that resulted in greater recovery of NGLs and less production of condensate Crude Oil – Gathered Volumes (MBbl/d) 21.18 28.85 Inclement weather and producer well shut-ins while completing new wells Transported Volumes (TBtu/d) 5.48 5.11 Increased supply in the Anadarko Basin Interstate Firm Contracted Capacity (Bcf/d) 7.23 7.17 Contracted expansion projects on EGT and incremental capacity contracted on Enable Mississippi River Transmission, LLC (MRT) Intrastate Transported Volumes (TBtu/d) 1.84 1.68 Increased supply in the Anadarko Basin

Operating Statistics by Basin

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1. Excludes condensate.

Three Months Ended March 31, 2017 2016

Anadarko Gathered volumes—TBtu/d 1.75 1.61 Natural gas processed volumes—TBtu/d 1.54 1.41 NGLs produced—MBbl/d(1) 67.30 58.58 Arkoma Gathered volumes—TBtu/d 0.57 0.62 Natural gas processed volumes—TBtu/d 0.10 0.10 NGLs produced—MBbl/d(1) 4.85 4.94 Ark-La-Tex Gathered volumes—TBtu/d 0.97 0.82 Natural gas processed volumes—TBtu/d 0.23 0.27 NGLs produced—MBbl/d(1) 7.61 9.95

Non-GAAP Reconciliations

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1. This amount reflects eliminations between the gathering and processing and transportation and storage segments of $118 million and $69 million for the three months ended March 31, 2017 and 2016, respectively. 2. This amount reflects eliminations between the gathering and processing and transportation and storage segments of $1 million for each of the three months ended March 31, 2017 and 2016. 3. This amount reflects eliminations between the gathering and processing and transportation and storage segments of $119 million and $70 million for the three months ended March 31, 2017 and 2016, respectively. 4. This amount reflects eliminations between the gathering and processing and transportation and storage segments of $118 million and $70 million for the three months ended March 31, 2017 and 2016, respectively.

Three Months Ended March 31, 2017 2016 (In millions)

Reconciliation of Gross margin to Total Revenues: Consolidated Product sales (1) $ 386 $ 245 Service revenue (2) 280 264 Total Revenues (3) 666 509 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) (4) 308 195 Gross margin $ 358 $ 314 Reportable Segments Gathering and Processing Product sales $ 351 $ 208 Service revenue 140 125 Total Revenues 491 333 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 286 165 Gross margin $ 205 $ 168 Transportation and Storage Product sales $ 153 $ 106 Service revenue 141 140 Total Revenues 294 246 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 140 99 Gross margin $ 154 $ 147

Non-GAAP Reconciliations Continued

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1. Other non-cash losses includes loss on sale

• f 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 three months ended March 31, 2017 and 2016. The March 31, 2016 amount represents 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. See below for a reconciliation of Adjusted interest expense to Interest expense. 4. Represents cash distributions declared for common and subordinated units outstanding as of each respective period. Amounts for 2017 reflect estimated cash distributions for common and subordinated units outstanding for the quarter ended March 31, 2017.

Three Months Ended March 31, 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 $ 120 $ 86 Depreciation and amortization expense 88 81 Interest expense, net of interest income 27 23 Income tax expense 1 1 Distributions received from equity method affiliate in excess of equity earnings 4 13 Non-cash equity based compensation 4 2 Change in fair value of derivatives (24 ) 8 Other non-cash losses(1) 1 1 Adjusted EBITDA $ 221 $ 215 Series A Preferred Unit distributions(2) (9 ) (4 ) Adjusted interest expense(3) (27 ) (23 ) Maintenance capital expenditures (14 ) (13 ) Current income taxes — (1 ) DCF $ 171 $ 174 Distributions related to common and subordinated unitholders (4) $ 137 $ 134 Distribution coverage ratio 1.25 1.30

Non-GAAP Reconciliations Continued

25

____________________ 1. Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies.

Three Months Ended March 31, 2017 2016 (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $ 27 $ 23 Amortization of premium on long-term debt 1 1 Amortization of debt expense and discount (1 ) (1 ) Adjusted interest expense $ 27 $ 23

Three Months Ended March 31, 2017 2016 (In millions)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 156 $ 117 Interest expense, net of interest income 27 23 Income tax expense 1 1 Deferred income tax (expense) benefit (1 ) — Changes in operating working capital which (provided) used cash: Accounts receivable (10 ) (24 ) Accounts payable 55 87 Other, including changes in noncurrent assets and liabilities 12 (11 ) Return of investment in equity method affiliate 4 13 Change in fair value of derivatives (24 ) 8 Other non-cash losses(1) 1 1 Adjusted EBITDA $ 221 $ 215

Forward Looking Non-GAAP Reconciliation

26

1. Outlook includes the fourth quarter 2017 distribution that will be paid in first quarter 2018

2017 Outlook (In millions)

Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to limited partners: Net income attributable to common and subordinated units $315 - $385 Add: Series A Preferred Unit distributions 36 Net income attributable to limited partners $351 - $421 Depreciation and amortization expense 350 - 360 Interest expense, net of interest income 114 - 122 Income tax expense 0 - 5 Distributions from equity method affiliates 32 - 36 Non-cash equity based compensation 12 - 16 Change in fair value of derivatives (25 - 35) Equity in earnings of equity method affiliates (22 - 28) Adjusted EBITDA $825 - $885 Less: Series A Preferred Unit distributions(1) 36 Adjusted interest expense 120 - 130 Maintenance capital expenditures 95 - 125 Current income taxes — Distributable cash flow $555 - $605

Forward Looking Non-GAAP Reconciliation Continued

27

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 2017 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 Other changes in non-current assets and liabilities.

2017 Outlook (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $114 - $122 Add: Amortization of premium on long-term debt 5 Capitalized interest on expansion capital 0 - 6 Less: Amortization of debt costs (0 - 4) Adjusted interest expense $120 - $130