4Q 2017 Earnings Presentation February 27, 2018 CRZO

Transcription

1 4Q 217 Earnings Presentation February 27, 218

2 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 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, 217exploration 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, 216 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, 216, File No , 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 3 4Q Overview Adjusted EPS Adjusted EBITDA Adjusted EBITDA Margin $.58 Exceeds consensus of $.57 $184MM Exceeds consensus of $171MM $32/Boe Up 23% versus 3Q Total Production Liquids Mix Year-end Reserves 62.4MBoe/d Exceeds high end of guidance 79% Of total production 262MMBoe Up 31% y/y

4 4 Executing on Corporate Initiatives Strategic Closed the divestitures of Marcellus and Utica Shale assets during the quarter Announced the divestitures of DJ Basin and Tier 1 Eagle Ford Shale assets (closed in January 218) Continued to work towards a free cash flow positive program by year-end 218 Operational Upgraded drilling fleet for Delaware Basin assets Continued to deliver strong results from recently-acquired Delaware Basin acreage Made significant progress on expansion of water disposal infrastructure necessary for future Delaware Basin production growth

5 218 Development Program 218 DC&I Capital Program - $775 MM Program Highlights 85%-9% Drilling & Completion Continued focus on high-return oily plays 2-rig development program in the Eagle Ford Shale 3-4-rig development program in the Delaware Basin Reflects a double digit increase in service costs Results in strong year-over-year production growth in 218 and sets up for strong growth in future years DC&I Capital Program Detail Eagle Ford Shale D&C $395 Delaware Basin D&C $29 Eagle Ford D&C Delaware Basin D&C Pipeline & Infra. Pipeline & Infrastructure $9 (All figures in $MM) 5 Note: 218 capital program estimates represent the midpoint of guidance range.

6 Net Daily Prod. (MBoe/d) Net Daily Prod. (MBbl/d) Strong Track Record of Growth Total Production Crude Oil Production 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 February 26, 218.

7 No. of Wells Eagle Ford Shale Operations Summary $/Boe MBoe/d 4Q Highlights Grew production by 7% sequentially Operating margin expanded by >25% versus the prior quarter Laid groundwork to begin completing multipads in 218 Historical Production Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Oil NGL Gas D&C Activity Operating Margin Q17 2Q17 3Q17 4Q17 Net Wells Drilled Net Wells Completed $6 $5 $4 $3 $2 $1 $- $6 $55 $5 $45 $4 $35 $3 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Operating Margin Production/Ad Val Tax Total LOE Average WTI Oil WTI Oil Price

8 Cumulative Production, MBo Eagle Ford Shale Increased Performance from 217 Drilling Program Quarterly Averages 216 Quarterly Averages Producing Days

9 9 Eagle Ford Shale Brown Trust Multipad Advantages of Multipad Development Reduces the number of parent-child relationships created over time Reduces the percentage of time wells need to be shut-in for offset completions over the project life Brown Trust multipad expected to result in 7%- 75% less parent well downtime relative to traditional 4-6 well pad development Minimizes number of times parent wells take frac hits over project life Existing Wells Multipad Wells Very important in areas where parent wells have been producing for extended periods of time as older wells are more susceptible to offset frac damage Results in better stimulation efficiency as fewer parent wells mean less ineffective frac fluid pumped during well completion Better multi-directional stress profile achieved during completion operations Completion crews

10 Eagle Ford Shale Well Economics Summary Oil, BOPD Cumulative Oil, MBO Type Curve Total Well Cost $4.5 MM Frac Stages Lateral Length 6,6 ft Gross 52 Mboe EUR Oil Only 382 Mbo 4 12 Net 376 Mboe 3 9 F&D Cost $11.9 / Boe IRR & NPV (1) $6 Oil $55 Oil $5 Oil IRR >1% NPV $5. MM IRR 79% NPV $4.1 MM IRR 58% NPV $3.2 MM Producing Months Daily Oil Cumulative Oil 6 3 NYMEX NPV1 Breakeven $32. (1) Economics based on NYMEX prices and include ~$1./Bbl deduct for oil, $3./Mcf NYMEX gas price, NGL pricing 35% of NYMEX oil price. (2) Total well cost includes ~$2K for allocated infrastructure. 1

11 No. of wells Delaware Basin Operations Summary $/Boe MBoe/d 4Q Highlights Successfully upgraded drilling fleet and transitioned legacy Permian learnings Continued delineating Phantom Area acreage with a focus on the Wolfcamp B bench Historical Production Made significant progress expanding future water disposal capacity 5 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Oil NGL Gas D&C Activity Operating Margin $4 $3 $2 $1 $6 $55 $5 $45 $4 WTI Oil Price 11. 1Q17 2Q17 3Q17 4Q17 Net Wells Drilled Net Wells Completed $- $35 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 Operating Margin Production/Ad Val Tax Total LOE Average WTI Oil

12 12 Delaware Basin Continued Delineation of Wolfcamp A and B Highlights Strong results seen from Wolfcamp A and B wells Reeves Ward Higher-than-expected flowing pressures from Wolfcamp B wells Processing yields have exceeded expectations, resulting in much stronger three-stream rates than forecast Wolfcamp A Wolfcamp B # 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) 1,621 (49% oil) 1,57 (49% oil) 2 State CVX Unit A1314 1H WCB 6,448 1,491 (55% oil) 1,476 (53% oil) 1,359 (53% oil) 3 McDermott St. Unit 172 WCA 9,396 1,855 (5% oil) 1,771 (5% oil) 1,667 (49% oil) 4 Woodson A36 1 WCB 9,968 1,61 (57% oil) 1,477 (58% oil) 1,38 (57% oil) 5 Dorothy Unit 38 #1 WCB 8,64 1,595 (65% oil) 6 Zeman-State A 442 1H WCA 7,654 2,21 (55% oil) *Two-stream production

13 Gross Volumes (Bbls/d) 13 Delaware Basin 3x Contracted Expansion of Piped Water-handling Capacity by Year-end 25, 2, Current Disposal Capacity Current Upgrade Delaware Zone SWD Well DBM Midstream Water Production Forecast year-end capacity: ~195, BWPD 15, 1, 5, Current capacity: 63, BWPD

14 Delaware Basin Well Economics Summary Oil BOPD, Gas - BOEPD Oil BOPD, Gas - BOEPD Cumulative Oil MBO, Gas - MBOE Cumulative Oil MBO, Gas - MBOE Type Curve Wolfcamp A Wolfcamp B 1,2 Wolfcamp A 3 Total Well Cost $9.5 MM $9.5 MM 1, 25 Frac Stages Lateral Length 7, ft. 7, ft Gross 1,648 Mboe 1,461 Mboe 4 1 EUR Oil Only 833 Mbo 649 Mbo 2 5 Net 1,236 Mboe 1,96 Mboe F&D Cost $7.65 / Boe $8.62 / Boe Producing Months IRR & NPV (1) $6 Oil $55 Oil IRR 93% 62% NPV $13.4 MM $9.2MM IRR 75% 49% NPV $11.4 MM $7.6 MM 1,2 1, Daily Oil Cumulative Oil Wolfcamp B Daily Wet Gas Cumulative Wet Gas $5 Oil IRR 59% 38% NPV $9.4 MM $5.9 MM NYMEX NPV1 Breakeven $26.5 $31.5 (1) Economics are three stream and based on NYMEX prices and include $3./Mcf gas price, $2./Bbl deduct for oil, $.5/Mcf deduct for gas, NGL pricing 35% of oil price. (2) Total well cost includes ~$45K for allocated infrastructure Producing Months

15 $/Boe $/Boe MBoe/d Financial Summary 4Q Highlights Revenue Drivers Exposure to premium-priced LLS market helped drive strong crude oil netbacks Unit LOE declined sequentially Adjusted EBITDA margin improved by 23% sequentially Q17 2Q17 3Q17 4Q17 $44 $42 $4 $38 $36 $34 $32 $3 $/Boe Production Unhedged Realized Price LOE Breakdown Adjusted EBITDA Margin $1 $7.76 $7.15 $6.86 $ $ $22.57 $24.11 $26.15 $ $ 1Q17 2Q17 3Q17 4Q17 SWD Workover Expense Repairs/Maintenance Equipment Chemicals Transport and Processing All Other Categories 1Q17 2Q17 3Q17 4Q17 Adjusted EBITDA Margin Cash G&A Production/Ad Val Tax LOE

16 Guidance Summary Highlights Delaware Basin expected to drive strong production growth in 218 Production should increase significantly in 2Q as the Brown Trust multipad comes online in the Eagle Ford Shale and additional water handling capacity comes online in the Dalaware Basin Unit LOE is expected to decline materially in 2Q as production ramps back up and workover activity returns to more normal levels 218 capex guidance factors in a double-digit increase in service costs Production Volumes: Actual Guidance 4Q 217 1Q 218 FY218 Total (Boe/d) 62,417 48,6-49,8 58,5-6,1 Crude Oil % 64% 65% - 67% 65% - 67% NGLs % 15% 15% - 17% 15% - 17& Natural Gas % 21% 17% - 19% 17% - 19% Unhedged Price Realizations: Crude Oil (% of NYMEX oil) 12.6% 99.% - 11.% N/A NGLs (% of NYMEX oil) 42.2% 33.% - 35.% N/A Natural Gas (% of NYMEX gas) 8.4% 91.% - 93.% N/A Cash (Paid) Received for Derivative Settlements, net ($MM) Costs and Expenses: $.6 ($16.) - (13.) N/A Lease Operating ($/Boe) $6.81 $8.5 - $9. $7.5 - $8.25 Production Taxes (% of Total Revenues) 4.63% 4.75% - 5.% 4.75% % Ad Valorem Taxes ($MM) $1.5 $2.3 - $2.8 $8. - $1. Cash G&A ($MM) $1.7 $24. - $24.5 $ $54.5 DD&A ($/Boe) $14.2 $ $14.75 $ $14.5 Interest Expense, net ($MM) $18.5 $ $16.8 N/A Capital Expenditures: Drilling and Completions ($MM) $21.4 N/A $75. - $8. Capitalized Interest ($MM) $12. $9.8 - $1.3 N/A 16

17 17 Non-GAAP Reconciliation Reconciliation of Net Loss Attributable to Common Shareholders (GAAP) to Adjusted Net Income Attributable to Common Shareholders (Non-GAAP) 4Q 217 In Thousands Per diluted Share Net Loss Attributable to Common Shareholders (GAAP) ($23,434) ($.29) Income tax expense 4,3.5 Loss on derivatives, net 86, Cash received for derivative settlements, net Non-cash general and administrative, net 6,194.8 Loss on extinguishment of debt 4,17.5 Other expense, net Adjusted income before income taxes 77, Adjusted income tax expense (29,737) (.37) Adjusted Net Income Attributable to Common Shareholders (Non-GAAP) $47,96 $.58 Diluted WASO (GAAP) 81,415 Dilutive shares adjustment 656 Adjusted Diluted WASO (Non-GAAP) 82,71

18 Non-GAAP Reconciliation Reconciliation of Net Income Attributable to Common Shareholders (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP) 1Q 217 2Q 217 3Q 217 4Q 217 (In thousands, except per Boe amounts) Net Income Attributable to Common Shareholders (GAAP) $4,21 $56,36 $5,574 ($23,434) Dividends on preferred stock ,249 5,532 Accretion on preferred stock Income tax expense ,3 Depreciation, depletion and amortization 54,382 59,72 67,564 81,571 Interest expense, net 2,571 21,16 2,673 18,52 (Gain) loss on derivatives, net (25,316) (26,65) 24,377 86,17 Cash received (paid) for derivative settlements, net 1,519 (261) 6, Non-cash general and administrative, net 2,14 1,582 5,494 6,194 Loss on extinguishment of debt ,17 Other expense, net Adjusted EBITDA (Non-GAAP) $94,165 $111,944 $132,849 $184,128 Cash interest expense, net (2,571) (21,16) (19,786) (17,824) Cash dividends on preferred stock (2,249) (5,532) Changes in components of working capital and other 2,814 11,99 (9,372) (18,388) Net Cash Provided by Operating Activities (GAAP) $76,48 $12,747 $11,442 $142,384 Adjusted EBITDA (Non-GAAP) $94,165 $111,944 $132,849 $184,128 Total production (MBoe) 4,173 4,643 5,8 5,742 Adjusted EBITDA Margin (Non-GAAP, $/Boe) $22.57 $24.11 $26.15 $