CRZO
1Q 2019 Earnings Presentation
May 8, 2019
1Q 2019 Earnings Presentation May 8, 2019 CRZO Forward Looking - - PowerPoint PPT Presentation
1Q 2019 Earnings Presentation May 8, 2019 CRZO Forward Looking Statements / Note Regarding Reserves This presentation contains statements concerning the Companys intentions, expectations, projections, assessments of risks, e stimations,
CRZO
1Q 2019 Earnings Presentation
May 8, 2019
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Forward Looking Statements / Note Regarding Reserves
This presentation contains statements concerning the Company’s intentions, expectations, projections, assessments of risks, estimations, beliefs, plans or predictions for the future,
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 the 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, 2019 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,” “possible,” “scheduled,” “guidance,” “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
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 10-K for the year ended December 31, 2018 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. 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, File No. 000-29187-87, and in our other filings with the SEC, available from the SEC on its website at www.sec.gov.
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1Q Overview
Above consensus expectations
Above consensus expectations
Driven by high-return Eagle Ford
Near high end of guidance
At low end of guidance
Adjusted EPS Adjusted EBITDA Adjusted EBITDA Margin Total Production Oil Production Total Operating Expense
Above high end of guidance
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4 1Q D&C Spend 1Q Infrastructure Spend Infrastructure Eagle Ford Delaware Basin
2019 Development Plan
On Track to Hit Full-year Budget
$525-$575 MM Budget
Note: 2019 updated guidance provided May 7, 2019. Values represent midpoint of ranges.
DC&I Remaining 1Q Net Activity vs. Capex
51% 46% 41% 33% 46% 36% 44% 46% 39%
Drilling Activity Completion Activity DC&I Capex Drilling Activity Completion Activity DC&I Capex Drilling Activity Completion Activity DC&I Capex
1Q Activity Remaining
Eagle Ford Delaware Basin Total Company 1Q D&C Spend 1Q Infrastructure Spend Eagle Ford Infrastructure Delaware Basin
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5 10 15 20 25 30 35 40 2Q18 3Q18 4Q18 1Q19
Net Wells Drilled Net Wells Completed
Eagle Ford Shale
Operations Summary
10 20 30 40 50 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19
MBoe/d
Oil NGL Gas
1Q Highlights Operated D&C Activity Historical Production Operating Margin
$0 $10 $20 $30 $40 $50 $60 $70 $- $10 $20 $30 $40 $50 $60 $70 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19
WTI Oil Price Margin ($/Boe)
Operating Margin Production/Ad Val Tax Total LOE Average WTI Oil
Completed two large-scale multipad projects
Continued to generate operational efficiencies Achieved 10%-15% reduction in drilling and completion costs vs. 4Q18
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Eagle Ford Shale
Strong Performance from Pena and RPG Multipads
33 total wells from Pena and RPG multipad projects Production began on schedule, with first sales recorded in February Wells performing in line with expectations Recent gross crude oil production of ~17,000 Bbls/d
Summary Total Oil Production
5 10 15 20 25 30 35 40 45 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000
Bbls/d
Gross Oil Production
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Eagle Ford Shale
Program Focused on Multipad Projects
Irvin Brown Trust Arnold
Area Well Count Total Frac Stages Average Lateral Brown Trust 13 413 ~6,400 ft. Irvin 14 481 ~6,900 ft. Arnold 9 420 ~9,300 ft.
Upcoming Multipad Projects
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$0 $10 $20 $30 $40 $50 $60 $70 $- $10 $20 $30 $40 $50 $60 $70 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19
WTI Oil Price Margin ($/Boe)
Operating Margin Production/Ad Val Tax Total LOE Average WTI Oil
2 4 6 8 10 2Q18 3Q18 4Q18 1Q19
Net Wells Drilled Net Wells Completed
Delaware Basin
Operations Summary
5 10 15 20 25 30 35 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19
MBoe/d
Oil NGL Gas
1Q Highlights Operated D&C Activity Historical Production Operating Margin
Completed initial multi-layer cube test with encouraging early results Production impacted by a significant increase in planned downtime Achieved additional efficiency gains
lateral foot compared to 4Q18 in Ford West
stage compared to 3Q18
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Delaware Basin
Conducting Cube Tests to Optimize Development
Crowley Pad 11H 10H 12H 11H 10H 12H
Note: Image not drawn to scale.
330’ 330’ 150’ 150’ 250’ Frac Sequencing Design Early Microseismic Takeaways
Microseismic data quality is excellent Data supportive of co-development concepts Constructive interference between wells indicates potential for:
influence frac geometry Carbonates are effective frac barriers and will impact:
12H
WCA Bounded WCA Bounded11H 10H 11H 10H 12H
WCA WCB Upper WCB Lower WCC
WCA Unbounded WCBU Unbounded WCBU Bounded WCBL Unbounded WCBL Bounded WCBL Bounded WCC Bounded WCC Unbounded Additional Completion TestsCRZO
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Delaware Basin
Encouraging Early Results from Initial Cube Test
10 20 30 40 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MBoe Days on Production
WCA WCB WCC 2,000 4,000 6,000 8,000 10,000 12,000
Boe/d
Summary Highlights
Early peak rate of ~10,600 Boe/d
Strong performance seen from Wolfcamp A wells Wolfcamp B wells performing in line with expectations Early performance from Wolfcamp C well exceeding expectations
Total Production1 Cumulative Production by Wolfcamp Layer2
13-stream production 22-stream productionUpcoming Cube Test
Dorothy-Sansom
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11 Exposure to premium-priced seaborne markets continued to drive strong crude oil netbacks Sequential production decline associated with limited TILs while multipads were being developed; significant increase in production expected during 2Q Total production near the high end of guidance range while crude oil production exceeded the high end of guidance range
Financial Summary
$0 $5 $10 2Q18 3Q18 4Q18 1Q19
$/Boe
LOE Breakdown
$7.54
Revenue Drivers
$7.34 $6.77
$0 $10 $20 $30 $40 $50 2Q18 3Q18 4Q18 1Q19
$/Boe
Adjusted EBITDA Margin Cash G&A Production/Ad Val Tax LOE
Adjusted EBITDA Margin 1Q Highlights
$30 $35 $40 $45 $50 $55 50 52 54 56 58 60 62 64 66 68 70 2Q18 3Q18 4Q18 1Q19 $/Boe MBoe/d
Production Unhedged Realized Price
$27.15 $27.41
SWD Workover Expense Repairs/Maintenance Rental Equipment Chemicals Transport and Processing All Other Categories
$34.45 $35.14 $6.90
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$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2019 2020 2021 2022 May 2023 April 2024 2025 July $MM 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 2016 2017 2018 Target Net Debt / Adjusted EBITDA
Historical Leverage Metrics1 Revolving Credit Facility
$1.25 billion borrowing base commitment
6.25% Senior Unsecured Notes
$650 million outstanding Currently callable
8.25% Senior Unsecured Notes
$250 million outstanding Callable on July 15, 2020
Corporate Credit Rating
B1 (Positive) / B+
6.25% Notes Revolver 8.25% Notes
Debt Maturity Profile
2 1As calculated by bank covenant. 2Balance as of 3/31/19.Targeting Leverage Below 2.0x
Balance Sheet Improvement Remains a Focus
Free Cash Flow Targeted for Debt Reduction
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Protect cash flows
Hedging Program
Disciplined Strategy Protects Cash Flows
Note: Hedge prices based on NYMEX oil reference price. 2019 percentage hedged based on midpoint of guidance.
Hedge 50%-75% of crude oil production Target floor price >$50/Bbl Maintain upside exposure
Hedge 50% of crude oil production Target floor price >$55/Bbl Protect cash flows Maintain upside exposure 2019 Program 2020+ Program Goals
Swaps Collars
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Guidance Summary
Highlights
Efficiency gains and cost savings contribute to a ~35% year-over-year reduction in CAPEX Production from multipads in both plays expected to drive strong production growth in 2Q Cost reduction efforts putting downward pressure on unit LOE during the year Expect to deliver free cash flow in the second half of 2019 Expect to deliver year-over-year production growth from 4Q18 to 4Q19
Actual Guidance 1Q 2019 2Q 2019 FY 2019
Production Volumes: Total (Boe/d) 61,960 66,500 - 67,500 66,800 - 67,800 Crude Oil % 66% 64% 63% NGLs % 16% 17% 17% Natural Gas % 18% 19% 20% Unhedged Price Realizations: Crude Oil (% of NYMEX oil) 100.9% 99.0% - 101.0% N/A NGLs (% of NYMEX oil) 34.5% 27.0% - 29.0% N/A Natural Gas (% of NYMEX gas) 76.7% 33.0% - 35.0% N/A Cash Paid for Derivative Settlements, net ($MM) $2.6 $6.0 - $10.0 N/A Costs and Expenses: Lease Operating ($/Boe) $7.54 $7.00 - $7.50 $6.75 - $7.50 Production & Ad Valorem Taxes (% of Total Rev.) 6.39% 6.25% - 6.75% 6.00% - 6.75% Cash G&A ($MM) $20.6 $10.0 - $10.5 $50.5 - $52.0 DD&A ($/Boe) $13.51 $13.00 - $14.00 $13.00 - $14.00 Interest Expense, net ($MM) $16.5 $17.5 - $18.5 N/A Capital Expenditures: Drilling and Completions ($MM) $214.7 N/A $525.0 - $575.0 Capitalized Interest ($MM) $9.0 $8.3 - $8.8 N/A
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1Q 2019 In thousands Per diluted Share Net Income Attributable to Common Shareholders (GAAP) $146,202 $1.58 Income tax benefit (179,395) (1.94) Loss on derivatives, net 83,284 0.90 Cash paid for derivative settlements, net (2,638) (0.03) Non-cash general and administrative, net 4,115 0.05 Non-recurring and other expense, net 4,358 0.05 Adjusted income before income taxes 55,926 0.61 Adjusted income tax expense1 (12,303) (0.14) Adjusted Net Income Attributable to Common Shareholders (Non-GAAP) $43,623 $0.47
Non-GAAP Reconciliation
Reconciliation of Net Income Attributable to Common Shareholders (GAAP) to Adjusted Net Income Attributable to Common Shareholders (Non-GAAP)
1For the three months ended March 31, 2019, adjusted income tax expense was calculated using a rate of 22.0%, which approximates the Company’s statutory tax rate adjustedfor ordinary permanent differences.
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2Q 2018 3Q 2018 4Q 2018 1Q 2019 (In thousands, except per Boe amounts) Net Income Attributable to Common Shareholders (GAAP) $30,095 $76,118 $255,120 $146,202 Dividends on preferred stock 4,474 4,457 4,367 4,360 Accretion on preferred stock 740 771 793 801 Income tax expense (benefit) 483 880 3,491 (179,395) Depreciation, depletion and amortization 72,430 80,108 82,525 75,322 Interest expense, net 15,599 15,406 15,891 16,451 (Gain) loss on derivatives, net 67,714 55,388 (159,407) 83,284 Cash paid for derivative settlements, net (24,083) (26,262) (31,597) (2,638) Non-cash general and administrative, net 7,206 3,183 (262) 4,115 Loss on extinguishment of debt
4,264 (1,091) (1,163) 4,358 Adjusted EBITDA (Non-GAAP) $178,922 $208,958 $170,668 $152,860 Cash interest expense, net (14,998) (14,791) (15,202) (15,848) Dividends on preferred stock (4,474) (4,457) (4,367) (4,360) Changes in components of working capital and other (22,302) (290) 37,164 (7,549) Net Cash Provided by Operating Activities (GAAP) $137,148 $189,420 $188,263 $125,103 Adjusted EBITDA (Non-GAAP) $178,922 $208,958 $170,668 $152,860 Total barrels of oil equivalent 5,193 5,946 6,286 5,576 Adjusted EBITDA Margin ($ per Boe) (Non-GAAP) $34.45 $35.14 $27.15 $27.41
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)