Enable Midstream Partners, LP

Transcription

1 Enable Midstream Partners, LP Second Quarter 2016 Conference Call August 3, 2016

2 Non-GAAP Financial Measures The Partnership 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 the Partnership s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess: The Partnership 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 the Partnership s assets to generate sufficient cash flow to make distributions to its partners; The Partnership 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 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 the Partnership's financial operating performance and cash distributions. The Partnership 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 from operations 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 an analytical tool 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 the Partnership s industry, its definitions of gross margin, Adjusted EBITDA, Adjusted interest expense, distributable cash flow and distribution coverage ratio may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 2

3 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 2016, 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. 3

4 Enable Midstream Highlights Enable is one of the top gathering and processing companies in the country in terms of customer drilling activity, driven by a strong focus on customer service and continued infrastructure investments 29 rigs are currently contractually dedicated to Enable 1, representing approximately 6% of the total US active rig count 2 The Bradley II processing plant, a 200 million cubic feet per day (MMcf/d) natural gas processing plant, is now fully operational Focused on continuous improvement, including deploying capital efficiently and reducing costs Declared a second quarter 2016 cash distribution of $0.318 per common and subordinated unit and a cash distribution of $0.625 per Series A Preferred Unit Achieved a distribution coverage ratio of 1.07x in second quarter 2016 Second Quarter 2016 Results In millions, except per unit and ratio data Q2-16 Q2-15 Net Income attributable to limited partners Net cash provided by operating activities $39 $77 $172 $96 Adjusted EBITDA 3 $196 $200 Distributable cash flow 3 $144 $139 Distributions per unit $0.318 $0.316 Distribution coverage ratio 1.07x 1.05x Expansion Capital $74 $ As of July 26, Rigs contractually dedicated to Enable as of July 26, 2016 compared to total U.S. rig count of 463 as reported by Baker Hughes as of July 29, Financial measures are non-gaap financial measures and are reconciled to the nearest GAAP financial measures in the appendix

5 Market-Leading SCOOP/STACK Position Enable s SCOOP and STACK Position SCOOP and STACK Map 4 #1 in Processing Capacity 1 Market-Leading Active Rig Count 2 Super-header System Interconnects ~1.7 Bcf/d Of Processing Capacity 3 ~1.9 Million Dedicated Gross Acres 3 ~240,000 Horsepower Of Field Compression 3 Announced We expect that the SCOOP/STACK to provide the highest oil production CAGR for the rest of the decade among all major oil basins. Goldman Sachs Upstream Equity Research, June 2016 We believe the STACK play has the potential to be the next franchise asset in the U.S. E&P. J.P. Morgan Upstream Equity Research, May 2016 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 51. Bentek processing capacity in associated SCOOP and STACK counties as of June 30, Drillinginfo rig count in associated SCOOP and STACK counties as of July 26, As of June 30, Rig data per Drillinginfo as of July 26, 2016, and Enable assets on map are as of July 18, 2016

6 Strong Producer Activity Across G&P Footprint Increased processed volumes in the Anadarko basin in Q2-16 compared to Q2-15 as a result of producer activity in the SCOOP and STACK Enable has recently seen improved gathering and processing volumes as a result of previously curtailed production returning to sales Bradley II Plant was placed in service in Q2-16 Gathering and Processing Highlights Enable now has 14 major processing plants with ~2.5 Bcf/d of processing capacity Approximately 89% of the active rigs in North Dakota are active in counties in which Enable operates 1 29 Active Rigs 2 on Enable s G&P Footprint STACK SCOOP Ark-La-Tex Williston Rigs contractually dedicated to Enable represent a significant percentage of the total active rigs in the respective plays SCOOP 3 STACK 3 Haynesville 4 Total Peers 40% Enable 60% Total Peers 62% Enable 38% Total Peers 64% Enable 36% Bradley Processing Complex 6 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. Per North Dakota s Department of Mineral Resources website as of July 30, Per Drillinginfo as July 26, 2016; represents rigs that are drilling wells that are contractually dedicated to Enable 3. Per Drillinginfo, there were 10 total rigs in the counties designated under SCOOP and 42 total rigs in counties designated under STACK as of July 26, Per Baker Hughes, there were 14 gas rigs operating in Haynesville as of July 29, 2016

7 Significant Fee-based Gross Margin from T&S Segment Highlights Transportation and Storage System System utilization demonstrates increased demand from power generation customers Interstate transportation volumes supporting power burn increased by 46% in Q2-16 compared to Q2-15 Enable s interstate and intrastate pipelines continue to provide residue transport solutions to the growing SCOOP and STACK plays Oklahoma interstate receipts increased by 13% in Q2-16 compared to Q2-15 Demand-driven customer base with over 65% of revenues from investment-grade customers 1 Segment accounts for over 40% of Enable s gross margin with over 90% of segment revenues from firm, fee-based contracts 7 1. Customers as of June 30, 2016; Standard and Poor s and Moody s credit rating from Bloomberg as of July 29, 2016 customers with split credit ratings are included as investment-grade entities

8 Operating Statistics Q Q Key Drivers: Q2-16 vs. Q2-15 Gathered volumes (TBtu/d) Natural gas processed volumes (TBtu/d) NGLs produced (MBbls/d) Condensate sold (MBbls/d) Crude Oil Gathered Volumes (MBbl/d) Transportation volumes (TBtu/d) Interstate firm contracted capacity (Bcf/d) Intrastate transported volumes (TBtu/d) Primarily lower Ark-La-Tex and Arkoma volumes Lower Ark-La-Tex and Arkoma volumes partially offset by higher Anadarko volumes Increased rich gas production in the Anadarko basin Increased rich gas production in the Anadarko basin Connection of new wells to Enable s Bear Den and Nesson crude oil gathering systems Lower demand on EGT for off-system deliveries Contract expirations for off-system deliveries on EGT EGT s Bradley Lateral now transporting firm, fee-based volumes that were previously transported as interruptible intrastate volumes 1. Excludes condensate 8

9 Financial Results Selected Results - $ in millions Q Q Key Drivers: Q2-16 vs. Q2-15 Revenue $529 $590 Gathering and Processing 1 $387 $422 Transportation and Storage 1 $225 $268 Gross Margin $275 $313 Gathering and Processing 1 $156 $181 Transportation and Storage 1 $119 $133 Operation and Maintenance & General and Administrative Expenses $120 $131 Lower natural gas sales resulting from lower gathered volumes and lower commodity prices and losses attributable to changes in fair value of condensate and NGL derivatives Losses attributable to changes in fair value of natural gas derivatives, lower natural gas sales associated with lower sales volumes and lower average sales price Losses attributable to changes in fair value of condensate and NGL derivatives, lower processed volumes and lower NGL prices Losses attributable to changes in fair value of natural gas derivatives and lower firm transportation revenues Lower employee expenses, reduced materials and supplies costs and lower costs related to integration and other contract services Depreciation and Amortization $83 $76 Additional assets placed into service Taxes other than Income Taxes $15 $13 Higher estimated ad valorem taxes Interest Expense $25 $23 Increase in the amount of debt outstanding 9 1. Excludes eliminations

10 Financial Results Continued Selected Results - $ in millions Q Q Key Drivers: Q2-16 vs. Q2-15 Net Income attributable to limited partners $39 $77 Losses attributable to changes in fair value of commodity derivatives, lower commodity prices, lower natural gas volumes sold and higher depreciation and amortization expense Adjusted EBITDA 1,2 $196 $200 Lower commodity prices, lower natural gas length volumes sold and lower distributions from SESH Series A Preferred Unit Distribution $9 $0 Issuance of Series A Preferred Units in Q1-16 Adjusted Interest Expense 2 $26 $28 Lower capitalized interest Maintenance Capital $17 $33 Lower information technology and pipe replacement spend in Q2-16 Distributable Cash Flow 2 $144 $139 Distribution Coverage Ratio x 1.05x Expansion Capital $74 $264 Monarch acquisition in Q2-15 and lower processing plant spend in Q In the Q4-15, the calculation of Adjusted EBITDA was changed to account for non-cash equity based compensation expense to be consistent with industry peers; historical Adjusted EBITDA reflect the calculation change 2. Financial measures are non-gaap financial measures and are reconciled to the nearest GAAP financial measures in the appendix

11 Key Highlights Strategically Located Assets Significant Size and Scale Long-term, Fee-based Contracts Financially Disciplined Assets are located in prominent natural gas and crude oil producer 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: ~12,400 miles of gathering systems, 14 major processing plants, ~7,900 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 Continue to prioritize efficient capital deployment and cost discipline Investment grade credit metrics and $1 billion of available liquidity 2 Strong distribution coverage Includes SESH, in which the Partnership owns a 50% interest 2. As of June 30, 2016; available liquidity calculated as Revolving Credit Facility of $1.75B less principal advances of $742MM less $3MM in letters of credit

12 12 Question and Answer Question & Answer

13 Appendix Appendix 13

14 Favorable Contract Structures and Credit Profile Commentary Enable s 2016 gross margin profile is expected to be approximately 96% fee-based or hedged Fee-Based Gross Margin Profile 1,3 11% 4% Certain gathering and processing contracts have provisions to protect against low commodity price environments and volume decreases 25% 60% Enable has a strong credit profile supported by $1 billion of available liquidity 2 and no near-term debt maturities $ in millions Term Loan Facility* EOIT Sr. Unsecured Notes ENBL Sr. Unsecured Notes Revolving Credit Facility No nearterm debt maturities through 2017 $450 $500 $1,750 $250 $600 $ Firm/MVC Fee-based Commodity-based Hedged 4.10x Other Fee-based Commodity-based Unhedged Debt Maturity Schedule Total Debt / LTM Adjusted EBITDA 4 * Term Loan includes option to request two, one-year extensions which could move the maturity to x 3.87x Q4-15 Q1-16 Q Gross margin profile represents Q3-16 through Q As of June 30, 2016; available liquidity calculated as Revolving Credit Facility of $1.75B less principal advances of $742MM less $3MM in letters of credit 3. Percentages in pie charts based on Gross Margin contribution 4. Calculated as Total Debt/LTM Adj. EBITDA from each quarter; Enable s LTM Adj. EBITDA is $801 million in Q4-15, $809 million in Q1-16 and $805 in Q2-16

15 2016 Financial, Operational and Capital Outlook Enable reaffirms its 2016 outlook, which is displayed below: $ in millions 2016 Financial and Operational Outlook Natural Gas Gathered Volumes (TBtu/d) Natural Gas Processed Volumes (TBtu/d) Crude Oil Gathered Volumes (MBbl/d) Net Income Attributable to Common and Subordinated Unit Holders $240 $310 Interest Expense (GAAP) $100 $110 Adjusted EBITDA 1 $780 $840 Preferred Equity Distributions 2 $32 Adjusted Interest Expense 1 $110 $120 Maintenance Capital $105 $125 Distributable Cash Flow 1 $535 $565 Distribution Coverage Ratio 1.0x or greater $ in millions 2016 Capital Outlook Gathering Pipeline, Compression and Related Capital ~$300 Processing Plants ~$50 Transportation and Storage Organic Growth, incl. EGT Expansion Project ~$25 Total Capital ~$ Financial measures are non-gaap financial measures and are reconciled to the nearest GAAP financial measures further on in the appendix 2. Outlook includes the fourth quarter 2016 distribution that will be paid in first quarter 2017

16 Price Sensitivities Impact to 2016 Net Income 1,2 % Change in Prices $ in millions +10% -10% Natural Gas and Ethane ($6) $6 NGLs (excluding ethane) and Condensate ($2) $2 Impact to 2016 Adjusted EBITDA 2 % Change in Prices $ in millions +10% -10% Natural Gas and Ethane $0 $0 NGLs (excluding ethane) and Condensate $2 ($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 2. Percent change in prices is from forecasted levels and includes the impact of hedges

17 Operating Statistics by Basin Anadarko Arkoma Ark-La-Tex Q2-16 Q2-15 Q2-16 Q2-15 Q2-16 Q2-15 Natural Gas Gathered Volumes (TBtu/d) Natural Gas Processed Volume (TBtu/d) Gross NGL Production (MBbl/d)

18 Hedging Summary 1 Commodity Natural Gas Exposure Hedged (%) 93% 63% Average Hedge Price ($/MMBtu) $2.69 $2.64 Crude 2 Exposure Hedged (%) 63% 32% Average Hedge Price ($/Bbl) $56.00 $46.87 Propane Exposure Hedged (%) 92% 49% Average Hedge Price ($/gal) $0.46 $ Percentage hedged includes hedges executed through July 22, Enable hedges net condensate/natural gasoline exposure with crude 3. Percentage hedged for 2016 reflects July-December hedges only Note: Table includes hedges and commodity exposures associated with equity volumes resulting from Enable's Gathering, Processing and Transportation businesses.

19 Non-GAAP Reconciliations Reconciliation of Gross margin to Revenues: Three Months Ended June 30, Six Months Ended June 30, (In millions) Consolidated Revenues $ 529 $ 590 $ 1,038 $ 1,206 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) Gross margin $ 275 $ 313 $ 589 $ 637 Reportable Segments Gathering and Processing Revenues $ 387 $ 422 $ 720 $ 823 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) Gross margin $ 156 $ 181 $ 324 $ 360 Transportation and Storage Revenues $ 225 $ 268 $ 471 $ 576 Cost of natural gas and natural gas liquids (excluding depreciation and amortization) Gross margin $ 119 $ 133 $ 266 $

20 Non-GAAP Reconciliations Continued Three Months Ended June 30, Six Months Ended June 30, (In millions, except distribution coverage ratio) 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 $ 39 $ 77 $ 125 $ 168 Add: Depreciation and amortization expense Interest expense, net of interest income Income tax expense EBITDA $ 147 $ 177 $ 338 $ 362 Add: Less: Distributions from equity method affiliates (1) Non-cash equity based compensation Other non-cash losses (2) Other non-cash gains (3) (3 ) Equity in earnings of equity method affiliates (7) (7 ) (14 ) (14) Adjusted EBITDA $ 196 $ 200 $ 411 $ 407 Less: Series A Preferred Unit distributions (4) (9) (13 ) Adjusted interest expense (5) (26) (28 ) (49 ) (50) Maintenance capital expenditures (17) (33 ) (30 ) (72) Current income taxes (1 ) (1 ) Distributable cash flow $ 144 $ 139 $ 318 $ 284 Distributions related to common and subordinated unitholders (6) $ 134 $ 132 $ 268 $ 266 Distribution coverage ratio Distributions from equity method affiliates includes a $7 million and $7 million return on investment and a zero and $8 million return of investment for the three months ended June 30, 2016 and 2015, respectively. Distributions from equity method affiliates includes a $14 million and $19 million return on investment and a $13 million and $8 million return of investment for the six months ended June 30, 2016 and 2015, respectively. Equity in earnings of equity method affiliates, net of distributions only includes those distributions representing a return on investment. 2. 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. 3. Other non-cash gains include lower of the cost or net realizable value adjustment recoveries upon the sale of the related inventory. 4. This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the three and six months ended June 30, 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 June 30,

21 Non-GAAP Reconciliations Continued Three Months Ended June 30, Six Months Ended June 30, (In millions) Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 172 $ 96 $ 289 $ 284 Interest expense, net of interest income Income tax expense Deferred income tax expense (1 ) (1) Equity in earnings of equity method affiliates, net of distributions (1) (8) (13) Non-cash equity based compensation (3) (3) (5) (6) Other non-cash items (6) 6 (6 ) 7 Changes in operating working capital which (provided) used cash: Accounts receivable 2 (2) (22) (2) Accounts payable (3) Other, including changes in noncurrent assets and liabilities (40) 4 (51 ) (22) EBITDA $ 147 $ 177 $ 338 $ 362 Add: Less: Non-cash equity based compensation Distributions from equity method affiliates (1) Other non-cash losses (2) Other non-cash gains (3) (3 ) Equity in earnings of equity method affiliates (7) (7 ) (14 ) (14) Adjusted EBITDA $ 196 $ 200 $ 411 $ Distributions from equity method affiliates includes a $7 million and $7 million return on investment and a zero and $8 million return of investment for the three months ended June 30, 2016 and 2015, respectively. Distributions from equity method affiliates includes a $14 million and $19 million return on investment and a $13 million and $8 million return of investment for the six months ended June 30, 2016 and 2015, respectively. Equity in earnings of equity method affiliates, net of distributions only includes those distributions representing a return on investment. 2. 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. 3. Other non-cash gains include lower of the cost or net realizable value adjustment recoveries upon the sale of the related inventory. 21

22 Non-GAAP Reconciliations Continued Reconciliation of Adjusted interest expense to Interest expense: Three Months Ended June 30, Six Months Ended June 30, (In millions) Interest Expense $ 25 $ 23 $ 48 $ 43 Add: Amortization of premium on long-term debt Capitalized interest on expansion capital Less: Amortization of debt costs (1) 1 (3) (1) Adjusted interest expense $ 26 $ 28 $ 49 $ 50 22

23 Forward Looking Non-GAAP Reconciliation 2016 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 $240 - $310 Add: Series A Preferred Unit distributions 22 Net income attributable to limited partners $262 - $332 Add: Depreciation and amortization expense Interest expense, net of interest income Income tax expense 0-5 EBITDA $692 - $787 Add: Less: Distributions from equity method affiliates Non-cash equity based compensation 5-10 Other non-cash losses (1) Other non-cash gains (2) Equity in earnings of equity method affiliates (25-30) Adjusted EBITDA $780 - $840 Less: Series A Preferred Unit distributions (3) 32 Adjusted interest expense Maintenance capital expenditures Current income taxes Distributable cash flow $535 - $ 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 2016 distribution that will be paid in first quarter 2017

24 Forward Looking Non-GAAP Reconciliation Continued 2016 Outlook (In millions) Reconciliation of Adjusted interest expense to Interest expense: Interest Expense $100 - $110 Add: Less: Amortization of premium on long-term debt 6 Capitalized interest on expansion capital 0-10 Amortization of debt costs (0-5) Adjusted interest expense $110 - $120 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 2016 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. 24