1Q 218 Earnings Presentation May 8, 218
Forward Looking Statements / Note Regarding Reserves This presentation contains statements concerning the Company s intentions, expectations, beliefs, projections, assessments of risks, estimations, plans or predictions for the future, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this presentation include, but are not limited to, statements relating to the Company s business and financial outlook, cost and risk profile of oil and gas exploration and development activities, quality and risk profile of Company s assets, liquidity and the ability to finance exploration and development activities, including accessibility of borrowings under the Company s revolving credit facility, commodity price risk management activities and the impact of our average realized prices, growth strategies, ability to explore for and develop oil and gas resources successfully and economically, estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities, drilling inventory, downspacing, infill drilling and completion optimization results, estimates regarding timing and levels of production or reserves, estimated ultimate recovery, the Company s capital expenditure plan and allocation by area, cost reductions and savings, efficiency of capital, the price of oil and gas at which projects break-even, future market conditions in the oil and gas industry, ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions, midstream arrangements and agreements, gas marketing strategy, lease terms, expected working or net revenue interests, the ability to adhere to our drilling schedule, acquisition of acreage, including number, timing and size of projects, planned evaluation of prospects, probability of prospects having oil and gas, working capital requirements, liquids weighting, rates of return, net present value, 217 exploration and development plans, any other statements regarding future operations, financial results, business plans and cash needs and all other statements that are not historical facts. Statements in this presentation regarding availability under our revolving credit facility are based solely on the current borrowing base commitment amount and amounts outstanding on such date. The amounts we are able to borrow under the revolving credit facility are subject to, and may be less due to, compliance with financial covenants and other provisions of the credit agreement governing our revolving credit facility. You generally can identify forward-looking statements by the words anticipate, believe, budgeted, continue, could, estimate, expect, forecast, goal, intend, may, objective, plan, potential, predict, projection, scheduled, should, or other similar words. Such statements rely on assumptions and involve risks and uncertainties, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, the Company s dependence on its exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, the Company s dependence on key personnel, factors that affect the Company s ability to manage its growth and achieve its business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base determinations (including determinations by lenders) and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, other actions by lenders, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability and completion of land acquisitions, cost of oilfield services and equipment, completion and connection of wells, and other factors detailed in the Risk Factors and other sections of the Company s Annual Report on Form 1-K for the year ended December 31, 217 and other filings with the Securities and Exchange Commission ( SEC ). Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Each forward-looking statement speaks only as of the date of the particular statement or, if not stated, the date printed on the cover of the presentation. When used in this presentation, the word current and similar expressions refer to the date printed on the cover of the presentation. Each forward-looking statement is expressly qualified by this cautionary statement and the Company undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. The information contained in this presentation does not purport to be all-inclusive or to contain all information that potential investors may require. 2 We may use certain terms such as Resource Potential that the SEC s guidelines strictly prohibit us from including in filings with the SEC. Our Probable (2P) and Possible (3P) reserves do not meet SEC rules and guidelines (including those relating to pricing) for such reserves. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 1-K for the year ended December 31, 217, File No. -29187-87, and in our other filings with the SEC, available from us at 5 Dallas, Suite 23, Houston, Texas, 772. These forms can also be obtained from the SEC by calling 1-8-SEC-33.
3 1Q Overview Adjusted EPS Adjusted EBITDA Adjusted EBITDA Margin $.48 Exceeds consensus of $.34 $136MM Exceeds consensus of $122MM $3/Boe Driven by High-margin Eagle Ford Total Production Oil Production Total Operating Expenses 51.3MBoe/d Exceeds high end of guidance 34.1MBbls/d Exceeds high end of guidance $16/Boe Below low end of guidance
4 Executing on Corporate Initiatives Strategic Closed the divestitures of DJ Basin and downdip Eagle Ford assets during the quarter Retired $37 million of debt and preferred stock Continued to work toward a development program capable of delivering double-digit growth within cash flow Operational Brought initial Eagle Ford Shale multipad online on schedule, and achieved targeted plateau production in early April Made significant progress on Permian Basin core area waterhandling system Continued to deliver strong well results from Delaware Basin acreage
218 Development Plan Synergistic Development of High-quality Assets $75 - $8 MM Capital Budget Eagle Ford D&C Delaware Basin D&C Pipeline & Infra. Area 85%-9% Drilling & Completion 218 Pro Forma Production Growth 1 218 Free Cash Flow 2 (Millions) Program Highlights Focus on high-return oily plays 2-rig development program in the Eagle Ford Shale 3-4-rig development program in the Delaware Basin Flexibility to move equipment and capital between plays Results in strong year-over-year production growth in 218 Sets up for strong growth in future years Actual Pro Forma Delaware Basin: Growth Engine >1% ~($17) 218 Total Production Growth 1% >3% Eagle Ford: High Return / FCF Positive 5%-1% ~$175 218 Crude Oil Production Growth 14% >2% 5 1 Production growth pro forma for ExL acquisition and downdip Eagle Ford divestiture. 2 Free cash flow calculated at the field level at strip prices of $66.8/Bbl and $2.79/Mcf.
Net Daily Prod. (MBoe/d) Net Daily Prod. (MBbl/d) Strong Track Record of Growth Total Production Crude Oil Production 7 6 17% CAGR 45 4 19% CAGR 35 5 3 4 25 3 2 2 15 1 1 5 FY15 FY16 FY17 FY18E FY15 FY16 FY17 FY18E Eagle Ford Delaware Basin DJ Basin Appalachia / Other 6 Note: 218 production based on midpoint of the guidance range provided on May 7, 218.
No. of Wells Eagle Ford Shale Operations Summary $/Boe MBoe/d 1Q Highlights Historical Production Completed the 16-well multipad development in the Brown Trust project area 5 4 Divested downdip Eagle Ford acreage during January Expanded operating margin by 7% versus the prior quarter 3 2 1 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 Oil NGL Gas D&C Activity 3 25 Operating Margin $6 $5 $65 $6 2 15 1 $4 $3 $2 $55 $5 $45 WTI Oil Price 5 $1 $4 2Q17 3Q17 4Q17 1Q18 $- 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 $35 7 Net Wells Drilled Net Wells Completed Operating Margin Total LOE Production/Ad Val Tax Average WTI Oil
8 MBbls/d, MMcf/d Eagle Ford Shale Strong Performance from Brown Trust Multipad Gross Production 14 12 1 8 6 4 Crude Oil 2 Wet Gas 3/31 4/5 4/1 4/15 4/2 4/25 4/3 Existing Wells Multipad Wells Summary 16 wells on 3 adjacent pads Pads completed simultaneously with 3 frac crews Project began producing on schedule, with first sales recorded in April Gross crude oil production from the project has been running >12, Bbls/d
No. of wells Delaware Basin Operations Summary $/Boe MBoe/d 1Q Highlights Delivered another strong Wolfcamp B well result Historical Production 16 Completed construction of 25, Bbl/d in-field water gathering and delivery system in Phantom core area 12 8 Worked to expand disposal capacity connected to the Phantom-area system; current capacity is ~125, Bbls/d Executed a firm transportation agreement on >9% of current gas production 4 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 Oil NGL Gas D&C Activity 8 Operating Margin $4 $65 6 4 2 $3 $2 $1 $6 $55 $5 $45 $4 WTI Oil Price 2Q17 3Q17 4Q17 1Q18 $- 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 $35 9 Net Wells Drilled Net Wells Completed Operating Margin Total LOE Production/Ad Val Tax Average WTI Oil
1 Delaware Basin Strong Results from Wolfcamp A and B MBoe* Cumulative Production 2 175 Reeves 1 2 3 5 4 6 Ward 15 125 1 75 Wolfcamp A Wolfcamp B 5 25 WCA WCB 3 6 9 12 Producing Days # Well Name Zone Lateral Length (ft.) 3-Day Rate* (Boe/d) 6-Day Rate* (Boe/d) 9-Day Rate* (Boe/d) 1 Christian 2 1T WCA 7,287 1,646 (5% oil) 1,625 (49% oil) 1,51 (49% oil) 2 Griffin State Unit 1922 1H WCB 9,752 1,929 (6% oil) 3 McDermott St. Unit 172 WCA 9,396 1,856 (5% oil) 1,771 (5% oil) 1,667 (49% oil) 4 Woodson A36 1 WCB 9,968 1,63 (57% oil) 1,477 (58% oil) 1,38 (57% oil) 5 Dorothy Unit 38 #1 WCB 8,64 1,595 (62% oil) 1,344 (62% oil) 1,287 (61% oil) 6 Zeman-State A 442 1H WCA 7,654 2,21 (55% oil) 1,617 (55% oil) 1,652 (54% oil) *Two-stream production
11 Water Management Initiatives Providing Capacity to Meet Future Phantom Area Growth Needs Gross Volumes (Bbls/d) Water-management Strategy Water-disposal Capacity Expansion 3K Company Owned Disposal Third Party Disposal Water Recycling Program 25K 2K 15K 1K Currently hold permits for waterdisposal wells totaling ~65 MBbls/d of capacity Third-party agreements currently in place for ~185 MBbls/d of capacity Targeting completion of an upcoming well with ~25% recycled water 5K K >25, Bbls/d Disposal Capacity by Mid 219 Disposal Capacity Online DBM Midstream Water Production Well Conversions Permitted SWD Wells
12 Delaware Basin Midstream Overview Crude Oil Significant Infrastructure and Optionality Cushing Houston/ MEH Local gathering and processing capacity is adequate for projected growth Crude Oil Oryx System Houston/ MEH Corpus Christi Corpus Christi Oryx system has 2 MBbl/d capacity with plans to double by late 219 Current 13.5 MBbl/d capacity on Oryx system expands to 25 MBbl/d in 2H18 First right of refusal on any unused or newly-added capacity Natural Gas Evaluating multiple proposals for longer term transport and sale Natural Gas DBM & ETC Enterprise- Gulf Coast Caprock has 14 MMcf/d capacity with additional 2 MMcf/d in 2H18 El Paso WAHA & West Coast ONEOK WAHA & Mexico Caprock Gathering & Processing WAHA Gulf Coast Markets Interconnects with ONEOK, El Paso, ETC, and Enterprise main lines allow access to Gulf Coast, West Coast, and Mexico Currently 4 MMcf/d firm capacity on ONEOK to WAHA through November 218 Legacy area gas capacity on DBM and ETC
$/Boe $/Boe MBoe/d Financial Summary 1Q Highlights Revenue Drivers Exposure to premium-priced LLS market drove strong crude oil netbacks Adoption of new revenue recognition standard drove a sequential increase in transportation expense and an offsetting increase in revenues Production and realized pricing exceeded expectations while cost control was better than expected 7 6 5 4 3 2 1 2Q17 3Q17 4Q17 1Q18 Production Unhedged Realized Price $5 $45 $4 $35 $3 $/Boe LOE Breakdown Adjusted EBITDA Margin $1 $7.76 $6.86 $6.81 $8.51 $5 $4 $5 $3 $2 $1 $24.11 $26.15 $32.7 $29.57 $ 2Q17 3Q17 4Q17 1Q18 $ 2Q17 3Q17 4Q17 1Q18 13 SWD Workover Expense Repairs/Maintenance Equipment Chemicals Transport and Processing All Other Categories Adjusted EBITDA Margin Production/Ad Val Tax Cash G&A LOE
Guidance Summary Highlights Brown Trust multipad expected to drive 2Q production growth Delaware Basin expected to drive strong production growth in 2H 18 Exposure of Eagle Ford production to premium LLS market expected to result in continued strong oil price realizations Unit LOE expected to decline materially in 2Q Production Volumes: Actual Guidance 1Q 218 2Q 218 FY 218 Total (Boe/d) 51,257 53,8-54,8 58,5-6,1 Crude Oil % 67% 67% 65% - 67% NGLs % 16% 15% 15% - 17% Natural Gas % 17% 18% 17% - 19% Unhedged Price Realizations: Crude Oil (% of NYMEX oil) 1.9% 97.% - 99.% N/A NGLs (% of NYMEX oil) 36.4% 32.% - 34.% N/A Natural Gas (% of NYMEX gas) 98.3% 75.% - 77.% N/A Cash Received (Paid) for Derivative Settlements, net ($MM) Costs and Expenses: ($14.4) ($25.5) - ($21.5) N/A Lease Operating ($/Boe) $8.51 $7.5 - $8. $7.5 - $8.25 Production Taxes (% of Total Revenues) 4.69% 4.75% - 5.% 4.75% - 5.% Ad Valorem Taxes ($MM) $2. $2. - $2.5 $7.5 - $9. Cash G&A ($MM) $22.7 $9.5 - $1. $52.5 - $54.5 DD&A ($/Boe) $13.98 $13.75 - $14.75 $13.5 - $14.5 Interest Expense, net ($MM) $15.5 $14.8 - $15.8 N/A Capital Expenditures: Drilling and Completions ($MM) $29.9 N/A $75. - $8. Capitalized Interest ($MM) $1.4 $8.5 - $9. N/A 14
Non-GAAP Reconciliation Reconciliation of Net Income Attributable to Common Shareholders (GAAP) to Adjusted Net Income Attributable to Common Shareholders (Non-GAAP) In Thousands 1Q 218 Per diluted Share Net Income Attributable to Common Shareholders (GAAP) $14,743 $.18 Income tax expense 319 -- Loss on derivatives, net 29,596.36 Cash paid for derivative settlements, net (14,365) (.17) Non-cash general and administrative, net 3,518.4 Loss on extinguishment of debt 8,676.11 Loss on redemption of preferred stock 7,133.9 Non-recurring and other expense, net 1,193.1 Adjusted income before income taxes 5,813.62 Adjusted income tax expense 1 (11,265) (.14) Adjusted Net Income Attributable to Common Shareholders (Non-GAAP) $39,548 $.48 1 Adjusted income tax expense is calculated by applying the Company s estimated annual effective income tax rates applicable to the adjusted income before income taxes which was 22.17% for the three months ending March 31, 218. 15
16 Non-GAAP Reconciliation Reconciliation of Net Income (Loss) Attributable to Common Shareholders (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP) 2Q 217 3Q 217 4Q 217 1Q 218 (In thousands, except per Boe amounts) Net Income (Loss) Attributable to Common Shareholders (GAAP) $56,36 $5,574 ($23,434) $14,743 Dividends on preferred stock -- 2,249 5,532 4,863 Accretion on preferred stock -- -- 862 753 Loss on redemption of preferred stock -- -- -- 7,133 Income tax expense -- -- 4,3 319 Depreciation, depletion and amortization 59,72 67,564 81,571 64,467 Interest expense, net 21,16 2,673 18,52 15,517 (Gain) loss on derivatives, net (26,65) 24,377 86,17 29,596 Cash received (paid) for derivative settlements, net (261) 6,456 59 (14,365) Non-cash general and administrative, net 1,582 5,494 6,194 3,518 Loss on extinguishment of debt -- -- 4,17 8,676 Non-recurring and other expense, net 24 462 517 1,193 Adjusted EBITDA (Non-GAAP) $111,944 $132,849 $184,128 $136,413 Cash interest expense, net (2,123) (19,786) (17,824) (14,855) Cash dividends on preferred stock -- (2,249) (5,532) (4,863) Changes in components of working capital and other 1,926 (9,372) (18,388) 22,29 Net Cash Provided by Operating Activities (GAAP) $12,747 $11,442 $142,384 $138,724 Adjusted EBITDA (Non-GAAP) $111,944 $132,849 $184,128 $136,413 Total production (MBoe) 4,643 5,8 5,742 4,613 Adjusted EBITDA Margin (Non-GAAP, $/Boe) $24.11 $26.15 $32.7 $29.57