TUDOR, PICKERING, HOLT 13 TH ANNUAL HOTTER N HELL ENERGY CONFERENCE Carrizo Oil & Gas June 20-22, 2017
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, 20167exploration 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 10-K for the year ended December 31, 2016 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 10-K for the year ended December 31, 2016, File No. 000-29187-87, and in our other filings with the SEC, available from us at 500 Dallas, Suite 2300, Houston, Texas, 77002. These forms can also be obtained from the SEC by calling 1-800-SEC-0330.
Carrizo Overview Deep Inventory of highly-economical drilling locations >160,000 net acres across the Eagle Ford Shale, Delaware Basin, and Niobrara Formation >2,000 net horizontal locations in inventory, equivalent to >775 MMBoe of net unbooked reserve potential, with significant additional upside potential Focus Areas Niobrara Formation Utica Shale Marcellus Shale Highly experienced, efficient operator Management team has drilled >800 horizontal wells EURs consistently rank among the best in our core areas Operating costs and margin consistently outperform peers Delaware Basin Eagle Ford Shale Solid financial position / liquidity First-quarter 2017 Net Debt-to-EBITDA of ~3.3x Significant liquidity available under the revolver No near-term debt maturities Hedged through 2018 Strong production growth Added a 3 rd full-time Eagle Ford rig in early 2017 Targeting 26% crude oil production growth in 2017 Targeting a 3-year crude oil production CAGR of >20% Net Acreage Position Net Undrilled Locations Eagle Ford Shale 103,300 >1,200 Delaware Basin 26,100 >240 Niobrara Formation 31,200 >640 Total >160,000 >2,000 3
Liquidity Position Remains Strong No Near-term Maturities and Ample Flexibility on the Revolver $MM $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 Production (MBbls/d) 40 35 30 25 20 15 10 5 0 $800 Revolver 2017 2018 July $50.13 Debt Maturities as of 3/31/2017 7.5% Notes 2019 2020 Sept Crude Hedges* $53.71 $53.86 6.25% Notes 2021 2022 2023 April $50.00 Q2'17 Q3'17 Q4'17 FY18 $80 $70 $60 $50 $40 $30 $20 $10 $0 Hedged Pricing $/Bbl Revolving Credit Facility $800 million borrowing base commitment with interest rate of LIBOR + 2.0%-3.0% Consortium of 19 banks led by Wells Fargo Restrictive covenants Total Net Debt < 4.0x TTM Adj. EBITDA 7.50% Senior Unsecured Notes (due 2020) $600 million outstanding Currently callable No liquidity or performance-based covenants 6.25% Senior Unsecured Notes (due 2023) $650 million outstanding Callable on April 15, 2018 No liquidity or performance-based covenants Corporate Credit Rating B2/B+ Swap Volume Weighted Average Floor Price Unhedged Production 4 *Q2 production based on midpoint of Q2 guidance provided May 9, 2017; Q3-Q4 production is implied based on full-year 2017 guidance.
2017 Capital Program Eagle Ford D&C 2017 Planned DC&I Capital Program - $540 MM 90% Drilling & Completion Delaware Basin D&C Other D&C Pipeline & Infra. Continued focus on high-return oily plays 3-rig development program in the Eagle Ford Further development / delineation of Delaware Basin assets Funds non-operated activity Results in strong year-over-year production growth in 2017 and sets up for strong growth in future years (All figures in $MM) CAPEX Program Detail Eagle Ford D&C 410 Delaware Basin D&C 45 Other D&C 30 Pipeline & Infrastructure 55 5 Note: 2017 capital program estimates represent the midpoint of guidance range.
6 Strong Multi-year Production Growth Outlook Total Production Crude Oil Production 60 50 Marcellus Utica / Other Delaware Basin Niobrara Eagle Ford 50 40 Net Daily Prod. (MBoe/d) 40 30 20 Net Daily Prod. (MBbls/d) 30 20 10 10 0 FY14 FY15 FY16 FY17E 0 FY14 FY15 FY16 FY17E FY18E FY19E
Eagle Ford Shale A Premier Industry Asset Acreage almost entirely in the volatile oil window 10-15 year drilling inventory with all locations identified, planned, and de-risked Multiple inventory expansion and completion optimization initiatives underway Eagle Ford Shale Overview Project To Date 523 gross / 462 net wells drilled 30 gross / 27 net wells WOC 2017 Operated Activity 3-rig drilling program Drill 106 gross / 91 net wells Frac 94 gross / 85 net wells Net Acres 103,300 Net Undrilled Locations >1,200 EUR / Well (Mboe) 300-700 Spacing Between Laterals (Ft.) 165-500 Effective Lateral Length (Ft.) ~6,300 Net Undrilled Resource Potential (1) (MMboe) >485 (1) Includes 99 MMboe of PUDs. 7
Eagle Ford Shale Optimizing Development Spacing Early stagger-stack results have been positive Prior development spacing was 330 between laterals Successful results at Brown Trust, RPG, and Irvin Ranch testing effective lateral spacing of 165 to 285 Five additional stagger stack pilots either online or being drilled and completed Future development potential in the Upper Eagle Ford and Austin Chalk Industry has successfully tested both formations in the Eagle Ford trend Carrizo drilled its initial Upper Eagle Ford test in 2015 No locations from either formation included in current inventory count Recent infill drilling test was successful Irvin 1H was drilled between two five-year-old wells Produced ~75 Mbo in 14 months Positive production response seen in offsetting parent wells Planning to drill initial infill test on recently-acquired acreage Continued success in spacing initiatives should lead to further expansion of drilling inventory and resource potential Potential Bench Development Austin Chalk Upper Eagle Ford Shale Lower Eagle Ford Shale Stagger Stack Initiative Buda 8
9 Eagle Ford Shale Optimizing Completion Techniques Cumulative Oil, MBO 110 100 90 80 70 60 50 40 30 Performance of Pena 50 vs. Pena 40 Pad Completed 28 wells with tighter frac stage spacing 200 stage-spaced wells have outperformed 240 stage-spaced wells by ~18% Tighter stage spacing also appears to minimize frac interference between new wells and offsetting parent wells Currently testing 175-180 stage spacing 20 10 0 0 30 60 90 120 150 180 210 Days on Production 200 stage-spaced well average 240 stage-spaced well average
Eagle Ford Shale Inventory Detail Area Arnold Winfield Inventory by Area 9% IRR Inventory by IRR (@ $55/Bbl NYMEX) Brown Trust 10% >100% 59% Gardendale 3% Irvin 15% NE LaSalle 3% 75%-100% 25% North LaSalle 22% Pena Jasik 8% RPG Mumme 3% 14% 50%-75% 7% Mumme East 2% Pierce SE Cotulla Tier 1 SE Cotulla Tier 2 4% 4% 3% <50% 9% Core Tier 1 10 Note: Eagle Ford locations reflect current inventory assumptions only. IRRs assume $3/Mcf NYMEX gas price.
Eagle Ford Shale Consistent Focus on Efficiency Gains Thousand Feet Effective Lateral Drilled per Rig-Month (6-month Avg.) 30 25 20 15 10 5 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2013 2014 2015 2016 2017 Historical Well Cost Trend Operational efficiencies in Q1 17 more than offset a double-digit increase in frac prices Dedicated frac crew currently completing ~8 stages per day versus ~7 in 2015 Currently drilling ~40% more wells per rigmonth versus 2015 pace Efficiency gains have helped drive a reduction in completed well costs despite an increase in average lateral length and frac stages per well $7 6,350 $6 6,300 Well Cost ($MM) $5 $4 $3 $2 $1 6,250 6,200 6,150 6,100 6,050 Lateral Length (ft.) $0 6,000 1Q'15 2Q'15 3Q'15 4Q'15 1Q'16 2Q'16 3Q'16 4Q'16 1Q'17 Avg. Well Cost Avg. Lateral Length 11
Eagle Ford Shale Well Economics Summary Type Curve Core Tier 1 Total Well Cost $4.0 MM $4.2 MM Frac Stages 31.6 32.1 Lateral Length 6,300 ft. 6,400 ft. Percent of Inventory 84% 16% EUR Gross 553 Mboe 403 Mboe Oil Only 423 Mbo 233 Mbo Net 419 Mboe 320 Mboe F&D Cost $9.55 / Boe $13.13 / Boe IRR & NPV (1) $75 Oil $65 Oil $55 Oil $45 Oil IRR >250% 96% NPV $9.2 MM $3.7 MM IRR >150% 56% NPV $7.1 MM $2.5 MM IRR 116% 28% NPV $5.1 MM $1.2 MM IRR 58% 10% NPV $3.0 MM NYMEX NPV10 Breakeven $30.50 $45.00 (1) Economics based on NYMEX prices and include ~$2.50/Bbl deduct for oil, $3.00/Mcf NYMEX gas price, NGL pricing 29% of NYMEX oil price. (2) Total well cost includes ~$200K for allocated infrastructure. Daily Average Oil, BOPD 700 650 600 550 500 450 400 350 300 250 200 150 100 50 0 0 2 4 6 8 10 12 14 16 18 20 22 24 Daily Production, BOPD Producing Months Cum Production, MBO 12 210 195 180 165 150 135 120 105 90 75 60 45 30 15 0 Cumulative Oil, MBO
Delaware Basin High-return, Stacked-pay Potential Targeting Wolfcamp formation in areas with potential for stacked-pay development Recent strong well results have delineated northern acreage position Nearby industry activity accelerating Continue to seek accretive acreage expansion opportunities Project To Date 8 gross / 8 net wells drilled 1 gross / 1 net well WOC 2017 Operated Activity Drill 6 gross / 6 net wells Frac 6 gross / 5 net wells Delaware Basin Overview Net Acres 26,100 Net Undrilled Locations >240 EUR / Well (Mboe) 900-2,100 Spacing between Laterals (Ft.) 660 Effective Lateral Length (Ft.) ~7,000 Net Undrilled Resource Potential (1) (MMboe) >275 (1) Includes 8 MMboe of PUDs. 13
Delaware Basin Potential Hydrocarbon Column of More Than 4,000 Five to seven potential development targets exist across the acreage position Current inventory count assumes development of only three layers Carrizo has production from the Wolfcamp A, Wolfcamp B, and Bone Spring Nearby industry wells also have production from the Wolfcamp X/Y and Wolfcamp C Operated activity currently focused on the Wolfcamp A Section is >200 thick Oiliest of target Wolfcamp formations Potential for two separate landing zones 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp X/Y Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D *Formations not drawn to scale. 14
15 Delaware Basin Initial Development Area BHP 113-10 1H 30-day rate: 1,110 Boe/d (48% oil, 52% wet gas) BHP 113-23x14 1H 30-day rate: 2,022 Boe/d (32% oil, 68% wet gas) Fortress State 1H 30-day rate: 1,520 Boe/d (25% oil, 36% gas, 39% NGL) BHP 113-24x1 1H 30-day rate: 961 Boe/d (52% oil, 48% wet gas) Corsair State 3H 30-day rate: 1,227 Boe/d (40% oil, 25% gas, 35% NGL) 3ROC Wise West State 0703WA 30-day rate: 1,399 Boe/d (40% oil, 60% gas) Liberator State 1H (30-day rate: 1,400 Boe/d (35% oil, 25% gas, 40% NGL)
Delaware Basin Well Economics Summary Type Curve Wolfcamp A Total Well Cost $7.0 MM 700 350 Frac Stages 31 Lateral Length EUR F&D Cost IRR & NPV (1) $75 Oil $65 Oil $55 Oil $45 Oil Gross Oil Net 7,000 ft. 1,862 Mboe 712 Mbo 1,396 Mboe $5.01 / Boe IRR ~200% NPV10 $18.3 MM IRR >150% NPV10 $14.7 MM IRR 92% NPV10 $11.1 MM IRR 57% NPV10 $7.6 MM NYMEX NPV10 Breakeven $23.75 Oil - BOPD, Gas - BOEPD 600 500 400 300 200 100 0 0 2 4 6 8 10 12 14 16 18 20 22 24 Producing Months Daily Oil Daily Wet Gas Cumulative Oil Cumulative Wet Gas 300 250 200 150 100 50 0 Cumulative Oil - MBO, Gas - MBOE 16 (1) Economics based on NYMEX prices and include $3.00/Mcf gas price, $4.00/Bbl deduct for oil, $0.97/Mcf deduct for gas, NGL pricing 30% of oil price. (2) Water disposal is assumed to be $0.75/bbl. (3) Total well cost includes ~$500K for allocated infrastructure. 16
17 Niobrara Formation Materially Improving Economics Acreage mostly HBP d Stacked-pay nature provides development potential in the Niobrara A, B, and C benches New completion designs resulting in 20%- 30% uplift in productivity Nearby industry testing of the deeper Codell formation could add another layer of potential Project To Date 132 gross / 59 net wells drilled Niobrara Formation Overview Net Acres 31,200 Net Undrilled Locations >640 EUR / Well (Mboe) 150-350 Spacing between Laterals (Ft.) 300/450 Effective Lateral Length (Ft.) 4,200 Net Undrilled Resource Potential (MMboe) >125
18 Summary Acreage position provides years of highreturn drilling inventory Solid financial position provides ample flexibility to fund growth Top-tier operational team with significant experience in unconventional plays Positioned to capitalize on opportunities
Appendix
Guidance Summary Production Volumes: Carrizo Production and Cost Guidance Trailing Four Quarter Actuals Q2 2017 and FY 2017 Guidance ACTUAL GUIDANCE * Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 FY 2017 Crude Oil (Bbls/d) 23,942 24,488 28,727 28,844 31,800-32,200 32,400-32,700 NGLs (Bbls/d) 5,217 4,730 5,048 4,508 4,800-5,000 5,300-5,500 Natural Gas (Mcf/d) 74,248 69,262 65,999 78,088 67,000-71,000 71,000-75,000 Equivalent Production (Boe/d) 41,533 40,762 44,775 46,367 47,767-49,033 49,533-50,700 Unhedged Price Realizations: Crude Oil (% of NYMEX oil) 92.2% 94.0% 94.6% 95.1% 94.0% - 96.0% N/A NGLs (% of NYMEX oil) 28.0% 28.7% 31.9% 35.3% 28.0% - 30.0% N/A Natural Gas (% of NYMEX gas) 63.8% 58.4% 68.4% 73.4% 67.0% - 72.0% N/A Realized Gain on Derivatives ($MM) $27.3 $20.4 $20.5 $1.5 ($1.5) - $1.5 N/A Costs and Expenses: Lease Operating ($/Boe) $6.12 $6.48 $6.71 $7.15 $7.25 - $7.75 $6.75 - $7.50 Production Taxes (% of Oil & Gas Revenues) 4.31% 4.40% 4.25% 4.10% 4.50% - 4.75% 4.25% - 4.75% Ad Valorem Taxes ($MM) $0.5 $1.4 $1.6 $3.0 $2.8 - $3.3 $11.0 - $13.0 G&A Expense (Cash only, $MM) $8.8 $9.7 $10.9 $19.7 $10.0 - $10.5 $50.0 - $52.0 DD&A Expense ($/Boe) $13.75 $13.05 $12.98 $13.03 $13.25 - $14.25 $13.25 - $14.25 Interest Expense, net ($MM) $19.0 $21.2 $20.5 $20.6 $21.0 - $22.0 N/A *Q2 and updated FY 2017 guidance provided on May 9, 2017. 20
Hedge Position Period Type of Contract Daily Volume (Bbl/d) Floor Price Ceiling Price Sub-floor Price % of Q2 Oil Forecast * Q2 2017 Total Volume 12,000 38% Swaps 12,000 $50.13 Q3 2017 Total Volume 12,000 38% Swaps 12,000 $53.71 Q4 2017 Total Volume 9,000 28% Swaps 9,000 $53.86 Q2-Q4 2017 Total Volume 10,996 Swaps 10,996 $52.46 FY 2018 Total Volume 6,000 19% 3-Way Collars 6,000 $50.00 $65.00 $40.00 Period Type of Contract Daily Volume (MMBtu/d) Floor Price Ceiling Price Sub-floor Price % of Q2 Gas Forecast * Q2 2017 Total Volume 20,000 28% Swaps 20,000 $3.30 Q3 2017 Total Volume 20,000 28% Swaps 20,000 $3.30 Q4 2017 Total Volume 20,000 28% Swaps 20,000 $3.30 Q2-Q4 2017 Total Volume 20,000 Swaps 20,000 $3.30 Note: Crude oil hedge position includes sold call options in 2018 2020. Volumes sold and weighted average ceiling prices are as follow: 3,388 Bbls/d at ~$71/Bbl in FY 2018, 3,875 Bbls/d at ~$74/Bbl in FY 2019, 4,575 Bbls/d at ~$76/Bbl in FY 2020. Carrizo also sold 33,000 MMBtu/d of call options on natural gas in 2017-2020. The weighted average ceiling price for these call options each year are as follow: $3.00/MMBtu in FY 2017, $3.25/MMBtu in FY 2018, $3.25/MMBtu in FY 2019, $3.50/MMBtu in FY 2020. 21 *Q2 2017 gas production guidance of 69.0 MMcf/d at midpoint, oil at 32,000 Bbls/d.
22 Eagle Ford Shale API Gravity 1Q 2017 Net Sales Revenue by Product Zavala Frio Atascosa Dimmit La Salle McMullen 4% 5% 91% Oil Gas NGL 1Q 2017 Volumes by API Gravity Source: DrillingInfo initial completion reports. 4% 1% 95% 50 46-49 35-45
Niobrara Formation Acreage Ranking Identified several discreet areas within Niobrara project and evaluated development potential and economics separately Ranking criteria: Geologic / petrophysical quality Activity level Production results 23
Niobrara Formation Type Curve Economics Type Curve Core/Tier 1 Total Well Cost $2.2 MM EUR Gross Oil Only Net 289 Mboe 217 Mbo 243 Mboe F&D Cost $9.05 / Boe IRR & NPV (1) $75 Oil $65 Oil $55 Oil $45 Oil IRR 146% NPV $3.2 MM IRR 103% NPV $2.3 MM IRR 46% NPV $1.4 MM IRR 21% NPV $0.6 MM NYMEX NPV10 Breakeven $39.25 (1) Economics based on NYMEX prices and include $2/Bbl deduct for oil, $3.00/Mcf NYMEX gas, NGL pricing 19% of NYMEX oil price. (2) Total well cost includes ~$315K for allocated infrastructure and artificial lift. Daily Production, BOPD Cum Production, MBO 24