Enable Midstream Partners, LP Fourth Quarter 2016 Conference Call - - PowerPoint PPT Presentation

Enable Midstream Partners, LP

Fourth Quarter 2016 Conference Call

February 21, 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.

2

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.

Business Performance Drives Q4-16 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

Fourth Quarter 2016 Operational Results

In millions, except per unit and ratio data

Q4-16 Q4-15 Net Income Attributable to Limited Partners $68 $65 Net Income Attributable to Common and Subordinated Units $59 $65 Net cash provided by operating activities $223 $235 Adjusted EBITDA1 $218 $172 Distributable cash flow (DCF)1 $132 $100 Distribution coverage ratio2 0.96x 0.75x Cash distribution per common and subordinated unit $0.318 $0.318 Cash distribution per Series A Preferred Unit $0.625 N/A Expansion capital $44 $168

Fourth Quarter 2016 Financial Results

Gathered Volumes Processed Volumes Transportation Volumes

Operation & Maintenance and General & Administrative Expenses (O&M and G&A)

3.04 3.19 Q4-15 Q4-16

4.9%

Growth

1.75 1.85 Q4-15 Q4-16

5.7%

Growth TBtu/d TBtu/d TBtu/d $ in millions

4.55 4.77 Q4-15 Q4-16

4.8%

Growth

$131 $122 Q4-15 Q4-16

6.9%

Reduction

T&S 42% G&P 58% 87% Fee-based

Achieved Full-Year 2016 Objectives

5

 Exceeded 2016 financial guidance1 for Adjusted

EBITDA and DCF

 Reduced O&M and G&A expenses by $57 million from

2015 to 2016

 Sized 2016 expansion capital to meet customer needs  Demonstrated capital markets access with a common

equity and preferred equity offering

 Improving cost of capital

Improved Distribution Coverage Ratio Lowered Total debt / Adjusted EBITDA2 Achieved Key 2016 Objectives Significant Fee-based Margin and Diverse Business Mix

2016 Gross Margin Profile

+ $1.1 B in revolver capacity3

4.10x 3.44x Year-end 2015 Year-end 2016 1.01x 1.18x 2015 2016

+ $100 MM in DCF in excess of 2016 distributions

1. 2016 guidance originally provided in Enable’s fourth quarter 2015 financial results press release dated February 17, 2016 2. Calculated as Total Debt/LTM Adj. EBITDA from each quarter; Enable’s LTM Adj. EBITDA was $801 million in Q4-15 and $873 million in Q4-16 3. As of December 31, 2016, available liquidity calculated as Revolving Credit Facility of $1.75B less principal advances of $636MM less $3MM in letters of credit

Commercial Successes

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Recent successes in both the gathering and processing and transportation and storage segments have strengthened Enable’s commercial and financial position

Gathering and Processing Transportation and Storage

• Signed a new 10-year, fee-based G&P contract in the STACK play that replaced a contract with a percent-
• f-proceeds (POP) processing arrangement
• Added over 60,000 gross acres of dedication to Enable in the STACK
• Signed a new 20-year, 228,000 dekatherms per day (Dth/d) intrastate firm transportation service

agreement with Oklahoma Gas & Electric

• Extended a 126,000 Dth/d interstate firm service agreement for 4 additional years
• Extended a 305,000 Dth/d intrastate firm service agreement for 1 additional year

Previously Announced Q4-16 Commercial Successes

Recent Commercial Successes Benefits Increase Fee-based Margin Reduce Commodity Exposure Extend Average Contract Life Support Continued Capital Deployment

   

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Volume Trends Driven by Strong Rig Activity in Major Oil and Gas Plays

1. Contractually dedicated rigs to Enable per Enable’s quarterly earnings press releases

Between

22 – 28

From Q4-15 to Q4-16 x Between

4 – 10

From Q4-15 to Q4-16

x

Anadarko Ark-La-Tex

~6% ~5%

Transportation

Volume growth from Q4-15 to Q4-16

~16%

TBtu/d

G&P Volumes Growing Year-on-Year Rig Activity Remains Strong

Dedicated Rig Count1

T&S Volumes Growing Year-on-Year

TBtu/d

G&P Volume Growth Dedicated Rigs T&S Volume Growth

25 22 22 23 23 3 4 4 5 8 10 Q4- 15 Q1- 16 Q2- 16 Q3- 16 Q4- 16

Ark-La-Tex Anadarko - Other Anadarko - SCOOP / STACK

~9%

Volume growth in Anadarko Basin from Q4-15 to Q4-16

Gathered Processed Gathered

Volume growth in Ark-La-Tex Basin from Q4-15 to Q4-16

Q4-15 Q1-16 Q2-16 Q3-16 Q4-16 1.57 1.39 0.81 1.67 1.52 0.94 Anadarko - Gathered Anadarko - Processed Ark-La-Tex - Gathered Q4-15 Q4-16 4.55 4.77 Q4-15 Q4-16

Financial Results

Financial Results

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1. Excludes eliminations

Three Months Ended Dec. 31 Twelve Months Ended Dec. 31

Selected Results – In millions

2016 2015 2016 2015 Revenue $614 $566 $2,272 $2,418

Gathering and Processing1 $465 $384 $1,640 $1,663 Transportation and Storage1 $268 $257 $1,024 $1,132

Gross margin $314 $325 $1,255 $1,321

Gathering and Processing1 $192 $174 $725 $755 Transportation and Storage1 $122 $151 $532 $567

Operation and Maintenance & General and Administrative Expenses $122 $131 $465 $522 Depreciation and Amortization $90 $85 $338 $318 Taxes other than Income Taxes $15 $14 $58 $59 Interest Expense $25 $24 $99 $90

Financial Results Continued

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1. Adjusted EBITDA, DCF and Adjusted Interest Expense are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures in the appendix 2. 2016 DCF includes $31 million of Series A Preferred Unit distributions while 2016 Net Income attributable to common and subordinated units includes $22 million of Series A Preferred Unit distributions 3. A non-GAAP measure calculated as DCF divided by distributions related to common and subordinated units

Three Months Ended Dec. 31 Twelve Months Ended Dec. 31

Selected Results – In millions, except ratio data

2016 2015 2016 2015 Net Income (Loss) Attributable to Limited Partners $68 $65 $312 ($752) Net Income (Loss) Attributable to Common and Subordinated Units $59 $65 $290 ($752) Net Cash Provided by Operating Activities $223 $235 $721 $726 Adjusted EBITDA1 $218 $172 $873 $801 Series A Preferred Unit Distributions2 $9 $0 $31 $0 Adjusted Interest Expense1 $27 $25 $103 $102 Maintenance Capital $50 $47 $101 $160 Distributable Cash Flow1 $132 $100 $639 $538 Distribution Coverage Ratio3 0.96x 0.75x 1.18x 1.01x Expansion Capital $44 $168 $282 $789

Well-positioned for 2017

Plays with Enable G&P assets

Improving Year-over-Year ½ Cycle Internal Rate of Returns1

Enable’s Footprint is Strategically Advantaged

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1. Per Bentek as of February 15, 2017; February 2017 price assumptions: a) Gas=12 month forward average curve for each regional pricing point (range $2.21 - $3.36/Mcf) b) Oil=12 month forward average WTI +/- differential (range $46.08 - $56.02/barrel) c) NGLs=weighted average $/barrel, 12-mo forward average Mt. Belvieu prices (range $26.36 - $31.99/barrel) 2. Source: Wood Mackenzie – North American Gas Tool as of February 13, 2017 3. South Central, Southeast & Gulf Coast represents natural gas demand in Texas, Oklahoma, Arkansas, Louisiana, Alabama, Mississippi and Florida, excluding LNG Exports and Mexico Exports

• Enable’s assets are located in some of the most attractive oil and gas plays in the country
• Strong producer returns are driving the outlook for long-term volume growth in several key plays

served by Enable

• Enable’s diverse suit of assets are well-positioned to provide a full range of services for growing

producer supply and market demand in and around its footprint

• 5.0%

0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% February 2017 August 2016

SCOOP/STACK/Cana Woodford Haynesville

1.6 2.9 2016 2026 5.1 8.4 2016 2026 Bcf/d Bcf/d

+1.3 +3.3

South Central, Southeast & Gulf Coast3 Gulf Coast LNG Exports

25.6 29.6 2016 2026 0.6 11.0 2016 2026 Bcf/d Bcf/d

+4.0

+10.4

Favorable Supply and Demand Outlook

Supply Outlook2 Demand Outlook2

Leading Gathering and Processing Assets and Acreage in SCOOP and STACK Plays

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Substantial Acreage Dedication and Interconnected Assets1 Market-Leading SCOOP/STACK Processing Capacity2

#1 in Processing Capacity

Note: SCOOP designated as Caddo, Carter, Garvin, Grady, McClain and Stephens counties of Oklahoma; STACK designated as Blaine, Canadian, Custer, Dewey, Kingfisher, Major and Woodward counties of Oklahoma 1. Rigs per Drillinginfo as of February 1, 2017; map as of February 6, 2017 and only includes processing plants located in the designated SCOOP and STACK counties 2. Per Bentek as of February 1, 2017; represents processing capacity in designated SCOOP and STACK counties

Enable is well- positioned to benefit from operational leverage associated with leading processing capacity investments

Significant Transportation and Storage Interconnectivity and Fee-based Margin

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Perryville Hub

Note: Map as of February 6, 2017 1. For the twelve months ending on December 31, 2016; excludes SESH which is reported as an equity investment 2. 50/50 joint venture with Spectra Energy Partners

EGT

(Enable Gas Transmission)

MRT

(Mississippi River Transmission)

SESH

(Southeast Supply Header)

• Access to Mid-continent supply and interconnects to pipelines serving Northeastern, Mid-continent and Gulf Coast markets
• 83% of transportation capacity is under firm contracts with a volume-weighted average contract life of 2.8 years
• Access to Mid-continent supply and Northeast supply from interconnects and serves utilities and end-users
• 95% of transportation capacity is under firm contracts with a volume-weighted average contract life of 2.5 years
• Access to Ark-La-Tex Basin supply and primarily serves customers that generate electricity for the Florida power market
• 100% of transportation capacity is under firm contracts with a volume-weighted average remaining contract life of 5.4 years
• Connectivity supports moving Anadarko Basin residue gas to end-user customers and other off-system markets
• Firm contracts on EOIT have a volume-weighted average remaining contract life of 4.9 years

EOIT

(Enable Oklahoma Intrastate Transmission)

T&S Interconnectivity

2

T&S Gross Margin1

Fee-based 98% EGT 59% MRT 14% EOIT 20%

Percent Fee-based Percent Derived from Firm Contracts

Key Highlights

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• Assets are located in prominent natural gas and crude oil producing basins with a

market-leading midstream position in the SCOOP and STACK plays

• Significant drilling activity across gathering and processing footprint
• Well-positioned to support the long-term supply and demand dynamics in the Mid-

Continent, Gulf Coast and Southeast regions

• Fully integrated suite of assets: ~12,900 miles of gathering systems, 14 major

processing plants with 2.5 Bcf/d of processing capacity, ~7,800 miles of interstate pipelines1, ~2,200 miles of intrastate pipelines and eight storage facilities comprising 85.0 Bcf of storage capacity

• High degree of interconnectivity between assets and end markets and consumers
• Favorable contract structure with significant fee-based and demand-fee margin
• Long-term contracts with large-cap producers and utilities, many of whom are

investment grade

• Continue to prioritize efficient capital deployment and cost discipline
• Investment grade credit metrics and $1.1 billion of available liquidity2
• Strong distribution coverage and consistent distributions to unitholders

Strategically Located Assets Significant Size and Scale Long-term, Fee-based Contracts Financially Disciplined

1. Includes SESH, in which Enable owns a 50% interest 2. As of December 31, 2016; available liquidity calculated as Revolving Credit Facility of $1.75B less principal advances of $636MM less $3MM in letters of credit

Question and Answer Question & Answer

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Appendix Appendix

17

18

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 Remains Unchanged

$ in millions

2017 Net Income Attributable to Common and Subordinated Unit Holders $315 – $385 Interest Expense $114 – $122 Adjusted EBITDA2 $825 – $885 Preferred Equity Distributions3 $36 Adjusted Interest Expense2 $120 – $130 Maintenance Capital $95 – $125 Distributable Cash Flow2 $555 – $605 Distribution Coverage Ratio 1.0x or greater

2017 Capital Outlook

$ in millions

2017 Gathering Related Expansion Capital $320 – $420 Processing Plants1 $90 – $100 Transportation and Storage Organic Growth $45 – $55 Total Capital $455 – $575

Note: 2017 Outlook originally released on November 2, 2016 1. Represents capital associated with the Wildhorse Plant, if elected to resume construction 2. Financial measures are non-GAAP financial measures and are reconciled to the nearest GAAP financial measures on slide 23 and 24 3. Includes the fourth quarter 2017 distribution that will be paid in the first quarter 2018 4. 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)4 $0.46 – $0.56 NGLs – Conway, Kansas ($/gal)4 $0.44 – $0.54 Crude Oil – WTI ($Bbl) $48.00 – $58.00

Derivative Activity and Price Sensitivities

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1. Price sensitivities 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 $3 ($3) NGLs (excluding ethane) and Condensate $4 ($4) Impact to 2017 Adjusted EBITDA (including impact of hedges) % Change in Prices

$ in millions

+10%

• 10%

Natural Gas and Ethane $3 ($3) NGLs (excluding ethane) and Condensate $4 ($5) Three Months Ended Dec. 31 Twelve Months Ended Dec. 31

$ in millions

2016 2015 2016 2015 Gain (Loss) on Derivative Activity ($21) $16 ($43) $39

Change in Fair Value of Derivatives ($20) $3 ($60) ($8) Realized Gain (Loss) on Derivative Activity ($1) $13 $17 $47

2017 Price Sensitivities1 2016 Derivative Activity

Gross Margin and Hedging Summary

20

1. Gross margin is based on hedges as of January 30, 2017, and Enable’s January 2017 price assumptions 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 February 2, 2017 3. Enable hedges net condensate/natural gasoline exposure with crude

Commodity 2017 Natural Gas

Exposure Hedged (%) 67% Average Hedge Price ($/MMBtu) $2.69

Crude3

Exposure Hedged (%) 72% Average Hedge Price ($/Bbl) $50.23

Propane

Exposure Hedged (%) 76% Average Hedge Price ($/gal) $0.49

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

2017 Margin Profile1

~93% fee- based or hedged

2017 Hedging Summary2

Operating Statistics

1. Excludes condensate

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Three Months Ended Dec. 31 Twelve Months Ended Dec. 31 2016 2015 2016 2015 Gathered volumes (TBtu/d) 3.19 3.04 3.13 3.14

Anadarko 1.67 1.57 1.65 1.59 Arkoma 0.58 0.66 0.62 0.67 Ark-La-Tex 0.94 0.81 0.86 0.88

Natural gas processed volumes (TBtu/d) 1.85 1.75 1.80 1.78

Anadarko 1.52 1.39 1.47 1.38 Arkoma 0.09 0.09 0.10 0.10 Ark-La-Tex 0.24 0.27 0.23 0.30

NGLs produced (MBbls/d)1 80.55 75.18 78.70 73.55

Anadarko 67.16 61.68 65.19 58.51 Arkoma 4.72 4.70 4.86 4.97 Ark-La-Tex 8.67 8.80 8.65 10.07

Condensate sold (MBbls/d) 4.48 4.52 5.27 5.13 Crude Oil – Gathered Volumes (MBbl/d) 21.93 23.04 25.00 13.86 Transportation volumes (TBtu/d) 4.77 4.55 4.88 4.97 Interstate firm contracted capacity (Bcf/d) 7.14 7.01 7.04 7.19 Intrastate transported volumes (TBtu/d) 1.71 1.82 1.72 1.84

Non-GAAP Reconciliations

22

Three Months Ended December 31, Twelve Months Ended December 31, 2016 2015 2016 2015 (In millions)

Reconciliation of Gross Margin to Total Revenues: Consolidated Product sales $ 335 $ 291 $ 1,172 $ 1,334 Service revenue 279 275 1,100 1,084 Total Revenues 614 566 2,272 2,418 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 300 241 1,017 1,097 Gross margin $ 314 $ 325 $ 1,255 $ 1,321 Reportable Segments Gathering and Processing Product sales $ 322 $ 243 $ 1,081 $ 1,118 Service revenue 143 141 559 545 Total Revenues 465 384 1,640 1,663 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 273 210 915 908 Gross margin $ 192 $ 174 $ 725 $ 755 Transportation and Storage Product sales $ 131 $ 123 $ 479 $ 590 Service revenue 137 134 545 542 Total Revenues 268 257 1,024 1,132 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 146 106 492 565 Gross margin $ 122 $ 151 $ 532 $ 567

Non-GAAP Reconciliations Continued

23

1. Distributions from equity method affiliate includes a $28 million and $34 million return

• n investment and a $15 million and $8

million return of investment for the years ended December 31, 2016 and 2015, respectively. 2. Other non-cash losses includes decreases in the fair value of derivatives, lower of cost or net realizable value adjustments, loss on sale

• f assets and write-downs of materials and

supplies. 3. Other non-cash gains includes lower of the cost or net realizable value adjustment recoveries upon the sale of the related inventory and increases in the fair value of derivatives. 4. This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the quarter and year ended on December 31, 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. 5. See below for a reconciliation of Adjusted interest expense to Interest expense. 6. Represents cash distributions declared for common and subordinated units outstanding as of each respective period. Amounts for 2016 reflect estimated cash distributions for common and subordinated units outstanding for the quarter ended December 31, 2016.

Three Months Ended December 31, Twelve Months Ended December 31, 2016 2015 2016 2015 (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 $ 68 $ 65 $ 312 $ (752 ) Add: Depreciation and amortization expense 90 85 338 318 Interest expense, net of interest income 25 24 99 90 Income tax expense (2 ) (2 ) 1 — EBITDA $ 181 $ 172 $ 750 $ (344 ) Add: Distributions from equity method affiliate (1) 3 5 43 42 Non-cash equity based compensation 4 2 13 9 Other non-cash losses (2) 35 6 96 36 Impairments 1 29 9 1,134 Less: Other non-cash gains (3) — (20 ) (10 ) (27 ) Noncontrolling Interest Share of Adjusted EBITDA — (14 ) — (20 ) Equity in earnings of equity method affiliate (6 ) (8 ) (28 ) (29 ) Adjusted EBITDA $ 218 $ 172 $ 873 $ 801 Less: Series A Preferred Unit distributions (4) (9 ) — (31 ) — Adjusted interest expense (5) (27 ) (25 ) (103 ) (102 ) Maintenance capital expenditures (50 ) (47 ) (101 ) (160 ) Current income taxes — — 1 (1 ) Distributable cash flow $ 132 $ 100 $ 639 $ 538 Distributions related to common and subordinated unitholders (6) $ 137 $ 134 $ 539 $ 534 Distribution coverage ratio 0.96 0.75 1.18 1.01

Non-GAAP Reconciliations Continued

24

1. Distributions from equity method affiliate includes a $28 million and $34 million return on investment and a $15 million and $8 million return of investment for the years ended December 31, 2016 and 2015,

• respectively. Equity in earnings of

equity method affiliate, net of distributions only includes those distributions representing a return on investment. 2. Other non-cash losses includes decreases in the fair value of derivatives, lower of cost or net realizable value adjustments, loss on sale of assets and write-downs of materials and supplies. 3. Other non-cash gains includes lower of the cost or net realizable value adjustment recoveries upon the sale of the related inventory and increases in the fair value of derivatives.

Three Months Ended December 31, Twelve Months Ended December 31, 2016 2015 2016 2015 (In millions)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 223 $ 235 $ 721 $ 726 Interest expense, net of interest income 25 24 99 90 Net loss (income) attributable to noncontrolling interest (1 ) 13 (1 ) 19 Income tax expense (benefit) (2 ) (2 ) 1 — Deferred income tax (expense) benefit 2 2 (2 ) 1 Equity in earnings of equity method affiliate, net of distributions (1) — 3 — (13 ) Impairments (1 ) (29 ) (9 ) (1,134 ) Non-cash equity based compensation (4 ) (2 ) (13 ) (9 ) Other non-cash items (7 ) (6 ) (14 ) 5 Changes in operating working capital which (provided) used cash: Accounts receivable (29 ) (50 ) (4 ) (15 ) Accounts payable (48 ) (53 ) 40 29 Other, including changes in noncurrent assets and liabilities 23 37 (68 ) (43 ) EBITDA $ 181 $ 172 $ 750 $ (344 ) Add: Impairments 1 29 9 1,134 Non-cash equity based compensation 4 2 13 9 Distributions from equity method affiliate 3 5 43 42 Other non-cash losses (2) 35 6 96 36 Less: Other non-cash gains (3) — (20 ) (10 ) (27 ) Noncontrolling Interest Share of Adjusted EBITDA — (14 ) — (20 ) Equity in earnings of equity method affiliate (6 ) (8 ) (28 ) (29 ) Adjusted EBITDA $ 218 $ 172 $ 873 $ 801

Non-GAAP Reconciliations Continued

25

Three Months Ended December 31, Twelve Months Ended December 31, 2016 2015 2016 2015 (In millions)

Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $ 25 $ 24 $ 99 $ 90 Add: Amortization of premium on long-term debt 2 1 6 5 Capitalized interest on expansion capital — 1 1 10 Less: Amortization of debt expense — (1 ) (3 ) (3 ) Adjusted interest expense $ 27 $ 25 $ 103 $ 102

Forward Looking Non-GAAP Reconciliation

26

1. Other non-cash losses includes changes in the fair value of derivatives, lower of cost or net realizable value adjustments, loss on sale of assets and write- downs of materials and supplies. 2. Other non-cash gains include lower of the cost or net realizable value adjustment recoveries upon the sale of the related inventory. 3. 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 Add: Depreciation and amortization expense 335 - 345 Interest expense, net of interest income 114 - 122 Income tax expense 0 - 5 EBITDA $800 - $893 Add: Distributions from equity method affiliates 32 - 36 Non-cash equity based compensation 12 - 16 Other non-cash losses(1) — Less: Other non-cash gains(2) (12 - 18) Equity in earnings of equity method affiliates (22 - 28) Adjusted EBITDA $825 - $885 Less: Series A Preferred Unit distributions(3) 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