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 of 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 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 opportunities. 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. 3
Business Performance Drives Q4-16 Results Fourth Quarter 2016 Operational Results Fourth Quarter 2016 Financial Results Gathered Volumes TBtu/d Transportation Volumes TBtu/d 3.04 3.19 Q4-15 Q4-16 4.55 4.9% Growth 4.8% Growth 4.77 Processed Volumes TBtu/d 1.75 1.85 Q4-15 Q4-16 Operation & Maintenance and General & Administrative Expenses (O&M and G&A) $ in millions $131 5.7% Growth 6.9% Reduction $122 In millions, except per unit and ratio data Q4-16 Q4-15 Net Income Attributable to Limited Partners Net Income Attributable to Common and Subordinated Units Net cash provided by operating activities $68 $65 $59 $65 $223 $235 Adjusted EBITDA 1 $218 $172 Distributable cash flow (DCF) 1 $132 $100 Distribution coverage ratio 2 0.96x 0.75x Cash distribution per common and subordinated unit Cash distribution per Series A Preferred Unit $0.318 $0.318 $0.625 N/A Expansion capital $44 $168 Q4-15 Q4-16 Q4-15 Q4-16 4 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
Achieved Full-Year 2016 Objectives Achieved Key 2016 Objectives Exceeded 2016 financial guidance 1 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 Lowered Total debt / Adjusted EBITDA 2 + $1.1 B in revolver capacity 3 4.10x Improved Distribution Coverage Ratio + $100 MM in DCF in excess of 2016 distributions 1.01x Significant Fee-based Margin and Diverse Business Mix 2016 Gross Margin Profile 1.18x 2015 2016 3.44x G&P 58% 87% Fee-based T&S 42% Year-end 2015 Year-end 2016 5 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 Recent successes in both the gathering and processing and transportation and storage segments have strengthened Enable s commercial and financial position Previously Announced Q4-16 Commercial Successes Gathering and Processing Signed a new 10-year, fee-based G&P contract in the STACK play that replaced a contract with a percentof-proceeds (POP) processing arrangement Added over 60,000 gross acres of dedication to Enable in the STACK Transportation and Storage 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 Recent Commercial Successes Benefits Increase Fee-based Margin Reduce Commodity Exposure Extend Average Contract Life Support Continued Capital Deployment 6
Volume Trends Driven by Strong Rig Activity in Major Oil and Gas Plays Ark-La-Tex Anadarko Dedicated Rigs G&P Volume Growth T&S Volume Growth Between 22 28 From Q4-15 to Q4-16 Between 4 10 From Q4-15 to Q4-16 x x ~6% Gathered ~16% ~9% Volume growth in Anadarko Basin from Q4-15 to Q4-16 Gathered Processed Volume growth in Ark-La-Tex Basin from Q4-15 to Q4-16 ~5% Transportation Volume growth from Q4-15 to Q4-16 Rig Activity Remains Strong Dedicated Rig Count 1 G&P Volumes Growing Year-on-Year TBtu/d T&S Volumes Growing Year-on-Year TBtu/d 3 25 22 22 23 23 1.57 1.67 1.39 1.52 0.81 0.94 4.55 4.77 4 4 5 8 10 Q4-15 Q1-16 Q2-16 Q3-16 Q4-16 Ark-La-Tex 15 16 Anadarko - Other 16 Anadarko 16 - SCOOP 16/ STACK Anadarko - Gathered Anadarko - Processed Ark-La-Tex - Gathered Q4-15 Q4-16 Q4-15 Q4-16 7 1. Contractually dedicated rigs to Enable per Enable s quarterly earnings press releases
Financial Results
Financial Results 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 Processing 1 $465 $384 $1,640 $1,663 Transportation and Storage 1 $268 $257 $1,024 $1,132 Gross margin $314 $325 $1,255 $1,321 Gathering and Processing 1 $192 $174 $725 $755 Transportation and Storage 1 $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 9 1. Excludes eliminations
Financial Results Continued 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 Net Income (Loss) Attributable to Common and Subordinated Units $68 $65 $312 ($752) $59 $65 $290 ($752) Net Cash Provided by Operating Activities $223 $235 $721 $726 Adjusted EBITDA 1 $218 $172 $873 $801 Series A Preferred Unit Distributions 2 $9 $0 $31 $0 Adjusted Interest Expense 1 $27 $25 $103 $102 Maintenance Capital $50 $47 $101 $160 Distributable Cash Flow 1 $132 $100 $639 $538 Distribution Coverage Ratio 3 0.96x 0.75x 1.18x 1.01x Expansion Capital $44 $168 $282 $789 10 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
Well-positioned for 2017
Enable s Footprint is Strategically Advantaged 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 Improving Year-over-Year ½ Cycle Internal Rate of Returns 1 Plays with Enable G&P assets Favorable Supply and Demand Outlook Supply Outlook 2 Demand Outlook 2 40.0% 35.0% 30.0% 25.0% 20.0% 15.0% 10.0% 5.0% 0.0% -5.0% SCOOP/STACK/Cana Woodford Bcf/d 2.9 1.6 +1.3 2016 2026 Haynesville Bcf/d 8.4 5.1 South Central, Southeast & Gulf Coast 3 Bcf/d 29.6 25.6 +4.0 2016 2026 Gulf Coast LNG Exports Bcf/d 11.0 February 2017 August 2016 +3.3 2016 2026 0.6 +10.4 2016 2026 12 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
Leading Gathering and Processing Assets and Acreage in SCOOP and STACK Plays Substantial Acreage Dedication and Interconnected Assets 1 Market-Leading SCOOP/STACK Processing Capacity 2 #1 in Processing Capacity Enable is wellpositioned to benefit from operational leverage associated with leading processing capacity investments 13 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
Significant Transportation and Storage Interconnectivity and Fee-based Margin T&S Interconnectivity T&S Gross Margin 1 Percent Fee-based Percent Derived from Firm Contracts Perryville Hub Fee-based 98% EGT 59% MRT 14% EOIT 20% EGT (Enable Gas Transmission) 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 MRT (Mississippi River Transmission) 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 EOIT (Enable Oklahoma Intrastate Transmission) 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 2 SESH (Southeast Supply Header) 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 14 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
Key Highlights Strategically Located Assets Significant Size and Scale Long-term, Fee-based Contracts 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 pipelines 1, ~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 Financially Disciplined Continue to prioritize efficient capital deployment and cost discipline Investment grade credit metrics and $1.1 billion of available liquidity 2 Strong distribution coverage and consistent distributions to unitholders 15 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
16 Question and Answer Question & Answer
Appendix Appendix 17
2017 Outlook Remains Unchanged 2017 Operational Outlook 2017 Financial Outlook 2017 $ in millions 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 Capital Outlook Net Income Attributable to Common and Subordinated Unit Holders $315 $385 Interest Expense $114 $122 Adjusted EBITDA 2 $825 $885 Preferred Equity Distributions 3 $36 Adjusted Interest Expense 2 $120 $130 Maintenance Capital $95 $125 Distributable Cash Flow 2 $555 $605 Distribution Coverage Ratio 2017 Price Assumptions 1.0x or greater $ in millions 2017 2017 Gathering Related Expansion Capital $320 $420 Processing Plants 1 $90 $100 Transportation and Storage Organic Growth $45 $55 Total Capital $455 $575 Natural Gas Henry Hub ($/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 18 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
Derivative Activity and Price Sensitivities 2016 Derivative Activity 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 Sensitivities 1 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 ($5) 19 1. Price sensitivities based on current prices and current hedges 2. The impact of price sensitivities is the same for net income attributable to limited partners and net income attributable to common and subordinated units
Gross Margin and Hedging Summary 2017 Margin Profile 1 2017 Hedging Summary 2 ~93% feebased or hedged 8% 7% Commodity 2017 Natural Gas Exposure Hedged (%) 67% 32% Firm/MVC Fee-based Commodity-based Hedged 53% Other Fee-based Commodity-based Unhedged Average Hedge Price ($/MMBtu) $2.69 Crude 3 Exposure Hedged (%) 72% Average Hedge Price ($/Bbl) $50.23 Propane Exposure Hedged (%) 76% Average Hedge Price ($/gal) $0.49 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
Operating Statistics 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 21 1. Excludes condensate
Non-GAAP Reconciliations Three Months Ended December 31, Twelve Months Ended December 31, Reconciliation of Gross Margin to Total Revenues: Consolidated 2016 2015 2016 2015 (In millions) 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 22
Non-GAAP Reconciliations Continued 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: Less: 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 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 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. 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. 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. 23
Non-GAAP Reconciliations Continued 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: Less: 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 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 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. 24
Non-GAAP Reconciliations Continued 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: Less: Amortization of premium on long-term debt 2 1 6 5 Capitalized interest on expansion capital 1 1 10 Amortization of debt expense (1 ) (3 ) (3) Adjusted interest expense $ 27 $ 25 $ 103 $ 102 25
Forward Looking Non-GAAP Reconciliation 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: Less: Distributions from equity method affiliates 32-36 Non-cash equity based compensation 12-16 Other non-cash losses (1) 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 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 writedowns 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
Forward Looking Non-GAAP Reconciliation Continued 2017 Outlook (In millions) Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $114 - $122 Add: Less: Amortization of premium on long-term debt 5 Capitalized interest on expansion capital 0-6 Amortization of debt costs (0-4) Adjusted interest expense $120 - $130 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. 27