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JEFFERIES 2015 ENERGY CONFERENCE Carrizo Oil & Gas, Inc. November 12, 2015

CRZO 2 CRZO 2

Forward Looking Statements / Note Regarding Reserves

This presentation contain statements concerning the Company’s intentions, expectations, projections, assessments of risk, estimations, plans or predictions for the future, beliefs, 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, hedging activities, growth strategies, ability to explore for and develop oil and gas resources successfully and economically, estimates and forecasts of the timing, number and results of wells we expect to drill and other exploration activities, drilling inventory, downspacing, 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, changes in oil and gas prices, 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, 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 and 3-D seismic data, including number, timing and size of projects, planned evaluation of prospects, probability of prospects having oil and gas, acreage, working capital requirements, liquids weighting, rates of return, net present value, 2015 – 2016 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 elected 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 are inherently subject to risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, adverse market conditions and assessments, 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, 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, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and 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 our midstream and other industry partners, weather, actions by lenders, 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, risks associated with the trend towards increased anti-development activity, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability and completion of land acquisitions, 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, 2014 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 use certain terms in this presentation such as “Potential”, “Potential Reserves”, “Potential Exposure”, “Estimated Resource”, “Unrisked Exploration Potential” and “Unrisked Reserve Potential”, “Recoverable” and similar terms 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, 2014, 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.

This presentation includes “non-GAAP financial measures” as that term is defined in Regulation G. The most directly comparable GAAP financial measures and information reconciling these non-GAAP financial measures to the Company’s financial results prepared in accordance with GAAP are included at the end of this presentation.

CRZO 3 CRZO 3

Acreage focused on high-quality, low-cost oil and condensate resource plays Eagle Ford Shale, Delaware Basin, Utica Shale, and Niobrara Formation

Solid financial position / liquidity Net Debt-to-EBITDA of ~2.5x at end of Q3, pro forma for recent equity offering Significant liquidity available under the revolver No near-term debt maturities Well-hedged through 2016

Significant operational flexibility Leasehold obligations can be easily managed Ability to quickly ramp production growth back up as prices recover

Large resource potential >490 MMBoe of probable reserves, equivalent to ~3.2x proved reserves (1)

>55% of undrilled locations are economic (IRR > 10%) below $45/Bbl

Strong technical team Management team has drilled >750 horizontal wells EURs consistently rank among the best in our core areas Highly efficient drilling and completion operations

Carrizo Today Positioned for a Low Commodity Price Environment

(1) Based on internal estimate of reserves as of 9/30/15.

CRZO 4

9/30/15 Proved NPV10 ($MM)

Eagle Ford 1,502

Niobrara 63

Utica 30

Marcellus 59

Total 1,654

Portfolio of Assets

Marcellus Shale 32,800 net acres 18.5 MMBOE Proved

Utica Shale 28,700 net acres 1.6 MMBOE Proved

Niobrara Formation 35,100 net acres 5.9 MMBOE Proved

Eagle Ford Shale 84,000 net acres 129.4 MMBOE Proved

Delaware Basin 26,000 net acres

Notes: Based on 9/30/15 internal reserves and SEC pricing ($59.21/Bbl and $3.06/Mcf).

CRZO 5

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Source: ITG Investment Research. (1) Based on internal estimates.

Carrizo Acreage is Concentrated in Low-Cost Basins

Carrizo’s Eagle Ford Weighted Average Break-Even Cost is <$40/bbl (1)

CRZO 6 CRZO 6

Manage capex to preserve balance sheet and liquidity Financial leverage is below peer average and significant liquidity is available on the borrowing base

Manage leasehold obligations to preserve assets

Eagle Ford acreage can be held with <1 rig; minimal leasehold obligations in Utica and Niobrara Hold full-year average oil production roughly flat with 4Q 2014

Production guidance has been increased four times due primarily to strong well performance and operational efficiencies and yields growth vs. 4Q 2014

Drive cost reductions and efficiencies throughout operations

Eagle Ford wells costs are down >35% vs. late 2014 Test Delaware Basin acreage

Started flowback on initial two operated wells and recently TD’d third operated well Take advantage of opportunities to expand core positions

Acreage has been bolted-on in all core plays since the beginning of the year and additional offers are currently outstanding

Highlights of 2015 Plan

CRZO 7

$380

$25 $45 $30

$5 $55

Eagle Ford

Utica

Marcellus/ Other

Niobrara

2014 2015 Est.

Eagle Ford 519 380

Utica 48 25

Niobrara 108 45

Delaware Basin 1 30

Marcellus/Other 40 5

Land & Seismic 142 55

Total Capital 858 540

Land & Seismic Detail

Eagle Ford 20 Utica 5 Niobrara 15 Other Land 15 Seismic -

2015 Capital Program

Continued focus on oily plays

Results in growth vs. Q4 2014

Manages leasehold obligations

2016 D&C capital program expected to be significantly lower than 2015 given current commodity price outlook

Note: 2015 D&C capital estimates represent the midpoint of guidance range.

(All figures in $MM)

Delaware Basin

CRZO 8 CRZO 8

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Oil NGL Gas

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10.0

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35.0

40.0

Net

Dai

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rod,

(MBo

epd)

Eagle Ford Niobrara Utica Marcellus Barnett Other

Oil plays have driven growth in recent years

Targeting crude oil production growth of 21% Y-o-Y in 2015

Positioned to reaccelerate production growth as commodity prices recover

Downshifting Production Growth in 2015

26%

10%

64%

Note: 2015E production represents the midpoint of guidance.

% of Total

CRZO 9

Financial Leverage is Below Peer Average Net Debt / LTM EBITDA

Note: CRZO EBITDA computed in accordance with debt covenants and therefore debt is net of cash and excludes debt premium/discount; LTM EBITDA excludes/includes LTM EBITDA of assets sold/acquired. CRZO pro forma for recent equity offering. Note: Net debt is Q3’15 adjusted for Q4’15 capital market transactions and M&A. Peer companies include BCEI, EPE, FANG, GPOR, LPI, MTDR, OAS, PDCE, PE, PVA, REXX, RSPP, SN, WLL. Source: Bloomberg, Company reports.

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CRZO 10

Sustainable Growth Project Development Summary (1)

(1) Based on 9/30/15 internal reserves and SEC pricing ($59.21/Bbl and $3.06/Mcf). NPV10 value excludes future hedge gains of $99.2 million at the SEC price deck.

Undrilled Well Details (PUD & Probable)

Net Acres

Drillable Net

Acres

Net Proved

Developed Wells

Net Proved

Undeveloped Wells

Additional Net

Probable Wells

Total Net

Undrilled Wells

Effective Lateral Length

(Ft.) Frac

Stages

Spacing Between

Laterals (Ft.)

Well Spacing (Acres/

well) Eagle Ford 84,000 78,500 224 217 724 941 6,120 25 330/500 45/70 Niobrara 35,100 32,400 60 9 593 602 4,200 15 300/450 40/60 Utica 28,700 23,300 4 0 148 148 8,000 33 800 150 NE PA Marcellus 5,000 4,400 27 4 2 6 6,000 22 1,000 140 Total 152,800 138,600 315 230 1,467 1,697

Undrilled Undrilled

Proved Developed

Proved Undeveloped Probable

Total Undrilled

Total 2P

Proved Developed

Proved Undeveloped Probable

Total Undrilled

Total 2P

Eagle Ford 49.6 79.8 270.8 350.6 400.2 900 602 1,725 2,327 3,227 Niobrara 4.0 1.9 112.9 114.8 118.8 49 14 238 252 301 Utica 1.6 0.0 106.3 106.3 107.9 30 0 285 285 315 NE PA Marcellus 15.8 2.7 1.5 4.2 20.0 56 3 4 7 63 Total 71.0 84.4 491.5 575.9 646.9 1,035 619 2,252 2,871 3,906

Net Reserves (MMboe) NPV10 ($ Million)

CRZO 11 CRZO 11

Eagle Ford Shale The Premier Industry Asset

84,000 net acres Acreage almost entirely in the volatile oil window 15+ year drilling inventory with all locations identified, planned, and de-risked

Project To-Date 280 gross / 229 net wells drilled 27 gross / 25 net wells awaiting completion

2015 Operated Activity 2-3 rig program Drill 70 gross / 63 net wells Frac 67 gross / 60 net wells

CHK

EPE

EOG

CRZO Producing Pads Black Oil Gas CRZO Volatile Oil

MRO

CHK EOG

EOG

CRZO 12 CRZO 12

Eagle Ford Shale Optimizing the Development Program

500 Ft Spacing 330 Ft Spacing Black Oil Gas Volatile Oil

330 Ft Producer Stagger Stack 330 Ft Well 2H 2015

Performance of 330 ft. spaced wells looks very similar to wells drilled at wider spacing in each area tested

Testing further downspacing through stagger-stacks in the Lower Eagle Ford

Initial Upper Eagle Ford test on flowback

Testing a variety of completion enhancements including engineered completions, diversion techniques, increased proppant loading and advanced microseismic, and fiber optic monitoring

Upper EF Completion Optimization

LASALLE

CRZO 13 CRZO 13

Eagle Ford Shale Stagger Stack – Potential to Materially Expand Inventory

330 ft. 330 ft. 330 ft. 330 ft.

440 ft. 440 ft. 440 ft.

• Current development • 330 ft. effective spacing • ~1,090 total locations at

full 330 ft. spacing

• Full stagger stack • 165 ft. effective spacing • ~80% increase to

inventory

• Partial stagger stack • 220 ft. effective spacing • ~45% increase to

inventory

330 ft. 330 ft. 330 ft. 330 ft.

100 – 150 ft.

540 ft. 540 ft.

• Partial stagger stack • 270 ft. effective spacing • ~20% increase to

inventory

CRZO 14

>80% of locations have a WTI break-even cost of $39/Bbl or less

Eagle Ford Shale PV-10 Break-Even Oil Price by Project Area

4%

12%

8%

22%

13%

19%

3%

6%

4% 3% 2%

3%

$31.00

$34.50 $35.25

$35.50

$37.50 $38.25

$39.00

$45.00 $45.75

$47.00 $47.50 $48.50

-

5%

10%

15%

20%

25%

$30

$32

$34

$36

$38

$40

$42

$44

$46

$48

$50

% O

f Tot

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F Lo

catio

ns

PV-1

0 Br

eak-

Even

Oil

Pric

e ($

/Bbl

)

% Of Total EF LocationsPV-10 Break-Even Price

CRZO 15 CRZO 15

Eagle Ford Shale Well Economics Summary

Type Curve

Total Well Cost $4.6 MM

Frac Stages 25.5

Lateral Length 6,120 ft.

EUR

Gross 510 Mboe

Oil Only 393 Mbo

Net 380 Mboe

F&D Cost $12.11 / Boe

IRR &

NPV (1)

$75 NYMEX Oil IRR >100%

NPV $6.9 MM

$65 NYMEX Oil IRR 96%

NPV $5.1 MM


NPV $3.2 MM


NPV $1.4 MM NYMEX NPV10

Breakeven $38.00

(1) Economics include ~$2.75/Bbl deduct to NYMEX for oil; $3.00/Mcf NYMEX gas price; NGL pricing 23% of NYMEX oil price.

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BO

PD

Producing Months

Daily Production, BOPD Cum Production, MBO

CRZO 16 CRZO 16

Delaware Basin Wolfcamp Shale Focus Area

Carrizo focus (Wolfcamp Shale A Bench)

~26,000 net acres in Culberson and Reeves counties targeting the oil and condensate windows Initial development targeting

Culberson/Reeves border Continuing to block up other

acreage positions

Recent industry results have been strong following changes in completion techniques

Targeting Upper Wolfcamp A in areas with potential for Eagle Ford profitability

Potential for other stacked pay development Bone Springs Wolfcamp B Wolfcamp C Wolfcamp D / Cline

CRZO 17

12,400 net acres located along Culberson/Reeves border either closed or expected to close

Seek to create operated drilling units that support at least 7,500 ft. laterals

Acreage located near strong industry wells, as indicated on the following page

Flowing back initial two operated wells and recently TD’d third operated well

2015 Operated Activity 1 rig program Drill 5 gross / 4.2 net wells Frac 2 gross / 1.6 net wells

Cimarex

Capitan

BHP

EOG

Reeves Culberson

Delaware Basin Initial Development Area

CRZO 18 CRZO 18

Delaware Basin Nearby Industry Well Performance

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50

100

150

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250

0 6 12 18 24

Cum

ulat

ive

Oil

Prod

uctio

n (M

bbls

)

CRZO EF TC 6,000’ lateral

Cimarex

Capitan

BHP

Culberson Horizontal Wolfcamp A Wells

Months since first production

Chart Displays Oil Production For:

6 Cimarex Wolfcamp A Bench wells (3 are 2015 completions)

5 Capitan Wolfcamp A Bench wells

2 BHP wells (Horseshoe Springs)

Wells are normalized to 6,000’ lateral

EF type curve is shown for comparison

CRZO 19 CRZO 19

Utica Shale High-Rate, Rich-Condensate Focus Area

28,700 net acres Wagler wells’ condensate production exceeded type curve over first ~170 days by ~15% CGR remains strong at ~225 Bbls/MMcf

Evaluating potential for future well cost reductions Mostly 5 + 5 year and HBP leases ~35% HBP

Project To-Date 4 gross / 3 net wells drilled 16 gross / 12.8 additional wells drilled with spudder rig 6 pads built near midstream infrastructure

2015 Operated Activity

Fracked 2 gross / 1.7 net wells Prepare for Southern Guernsey infrastructure build-out

CRZO 20 20

Type Curve

3-String 2-String

Total Well Cost $9.0 MM $8.2 MM

EUR

Gross 898 Mboe

Condensate Only 451 Mbo

Net 727 Mboe

F&D Cost $12.38 / Boe $11.28 / Boe

IRR &

NPV(1)

$75 NYMEX Oil IRR 43% 54%

NPV $5.7 MM $6.5 MM


NPV $3.5 MM $4.3 MM


NPV $1.3 MM $2.1 MM

NYMEX NPV10 Breakeven

$49.00 $45.50

(1) Economics includes $7.50/Bbl deduct for condensate, 20% NYMEX oil for NGL mix assuming ethane rejection, and $3.00/Mcf NYMEX gas less $1.25/Mcf

Utica Shale Guernsey County Type Curve Economics

CRZO 21 CRZO 21

Niobrara Formation Preserving Option Value

Weld County

Noble

HBP Acreage

Non-HBP Acreage

Above oil-in-place cut-off

Below oil-in-place cut-off

35,100 net acres Have tested multiple benches and spacing configurations Participating in high-density projects with Noble and Whiting to test A, B, and C benches Plan to participate in a non-operated Codell test by early 2016


2015 Operated Activity Drilled 13 gross / 5 net wells Frac 11 gross / 6 net wells

CRZO 22

Niobrara weighted average break-even cost of $49/Bbl

Niobrara Formation PV-10 Break-Even Oil Price by Area

29%

45%

26%

$43.25

$51.25

$66.00

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5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

$30

$40

$50

$60

$70

$80

$90

$100

% O

f Tot

al N

io L

ocat

ions

PV-1

0 Br

eak-

Even

Oil

Pric

e ($

/Bbl

)

% Of Total Nio Locations

PV-10 Break-Even Price

CRZO 23 CRZO 23

Niobrara Formation Type Curve Economics

(1) $8/Bbl deduct to NYMEX oil; $3.00/Mcf NYMEX gas; NGL pricing 15% of NYMEX oil price.

Area 1 / 2A Type Curve

Total Well Cost $2.8 MM

EUR

Gross 289 Mboe

Oil Only 217 Mbo

Net 243 Mboe

F&D Cost $11.52 / Boe

IRR &

NPV (1)


NPV $2.9 MM


NPV $1.9 MM


NPV $0.9 MM NYMEX NPV10

Breakeven $45.75

Daily Production, BOPD Cum Production, MBO

CRZO 24 CRZO 24

Acreage position provides years of inventory with a best-in-class breakeven cost

Solid financial position provides liquidity to weather a prolonged downturn

Ample operational flexibility to reaccelerate or further decelerate quickly in response to commodity prices

Top-tier operational team with significant experience in unconventional plays

Positioned to capitalize on opportunities

Summary

Appendix

CRZO 26 CRZO 26

Guidance Summary

Carrizo Production and Cost Guidance Trailing Four Quarter Actuals

Q4 2015 and FY 2015 Guidance

ACTUAL GUIDANCE1

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 FY 2015

Production Volumes:

Crude Oil (Bbls/d) 22,130 21,373 22,284 23,573 24,100 - 24,500 22,850 - 22,950

NGLs (Bbls/d) 3,022 3,529 3,494 3,757 3,400 - 3,600 3,500 - 3,600

Natural Gas (Mcf/d) 75,283 58,159 62,042 51,710 52,000 - 56,000 56,000 - 57,000

Equivalent Production (Boe/d) 37,696 34,595 36,118 35,948 36,167 - 37,433 35,683 - 36,050

Unhedged Price Realizations:

Crude Oil (% of NYMEX oil) 94.6% 88.9% 94.7% 94.6% 91.0% - 93.0% N/A

NGLs (% of NYMEX oil) 26.5% 29.0% 20.6% 20.7% 18.0% - 23.0% N/A

Natural Gas (% of NYMEX gas) 63.9% 85.0% 54.5% 59.0% 53.0% - 58.0% N/A

Realized Gain on Derivatives ($MM) $12.0 $49.1 $45.1 $47.7 $48.0 - $49.0 N/A

Production Costs:

Lease Operating ($/Boe) $6.68 $6.97 $7.11 $6.72 $6.75 - $7.25 $6.85 - $7.05 Production Taxes (% of Oil & Gas Revenues) 4.21% 4.02% 4.07% 4.01% 4.25% - 4.50% 4.00% - 4.25%

Ad Valorem Taxes ($MM) $2.9 $3.0 $1.7 $2.0 $2.0 - $2.5 $9.0 - $9.5

G&A Expense (Cash only, $MM) $13.9 $18.5 $10.9 $11.7 $12.0 - $12.5 $53.1 - $53.6

DD&A Expense ($/Boe) $25.51 $23.73 $24.14 $24.57 $19.25 - $20.25 $22.75 - $23.25

(1) Updated Q4 and FY 2015 guidance provided on November 4, 2015.

CRZO 27 CRZO 27

Financial Position

Revolving Credit Facility (due 2018) Facility revised October 30, 2015

$685 million borrowing base commitment with interest rate of LIBOR + 1.50% - 2.50%

- Undrawn at October 30, 2015

Consortium of 19 banks led by Wells Fargo

Restrictive covenant: Net Debt < 4.75x TTM EBITDA for 2016

- < 4.375x in 2017, returning to < 4.0x thereafter

7.50% Senior Unsecured Notes (due 2020) $600 million outstanding

Callable on September 15, 2016

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 B1/B+

CRZO 28

Period Type of Contract Daily Volume (MMBtu/d) Floor Price Ceiling Price

Short Put Price

Basis Differential

Cash From Restructuring

($MM) % of Q4 Gas

Forecast1

Q4 2015 Total Volume 30,000 56% Swaps 30,000 $4.29

(1) Q4 2015 gas production guidance of 54.0 MMcf/d at midpoint, oil at 24,300 Bbls/d.

Period Type of Contract Daily Volume

(Bbl/d) Floor Price Ceiling Price Short Put

Price Basis

Differential

Cash From Restructuring

($MM) % of Q4 Oil Forecast1

Q4 2015 Total Volume 16,200 $39.0 67% Collars 16,200 $50.00 $67.34

Q1 2016 Total Volume 18,000 $18.3 74% Swaps 8,000 $60.03 Collars 10,000 $52.13 $72.60




FY 2016 Total Volume 14,807 $44.8 Swaps 9,315 $60.03 Collars 5,492 $50.97 $74.73

Hedge Position

Note: Crude oil hedge position includes sold call options in 2017-2020. Volumes sold and weighted average ceiling prices are as follow: 2,500 Bbls/d at $60.00/Bbl in FY 2017, 3,388 Bbls/d at $60.00/Bbl in FY 2018, 3,875 Bbls/d at $62.50/Bbl in FY 2019, 4,575 Bbls/d at $65.00/Bbl in FY 2020.

CRZO 29 CRZO 29

Eagle Ford Shale Operator Comparison

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2400

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400

BOPD

Eagle Ford March 2015 Average Production By Well

BOPD/Well Avg. TVD MCFD/Well

MCF

D

13000

12250

11500

10750

10000

9250

8500

7750

7000

TVD

,Ft

Source: IHS - Total Volume Divided by Active Wells for Companies with More than 100 Active Wells

CRZO 30

Eagle Ford Shale API Gravity

Source: DrillingInfo initial completion reports.

Dimmit

Zavala

Webb

Frio Atascosa

LaSalle

McMullen

92%

5%

3%

Q3 2015 Net Sales Revenue by Product

Oil

Gas

NGL

0%3%

97%

Q3 2015 Volumes by API Gravity

≥ 50

46 - 49

35 - 45

CRZO 31 CRZO 31

API gravities increase from NW to SE with increasing depth and thermal maturity

Trend-wise, data are very consistent and over the length of a 10,000’ wellbore gravities can change 2O in API

Light crudes generally classified as <= 50O API

Condensates generally classified as >50O API

The majority of Carrizo’s acreage is in the rich condensate/volatile oil window Rector gravity = 60O API Wagler gravity = 55O API Brown gravity = 49O API

API gravity trends are consistent with condensate gas ratios

Utica Shale Point Pleasant Condensate API Gravity

Rector

Brown

Lawsons

Waglers

CRZO 32 CRZO 32

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

CRZO 33 CRZO 33

Sickler

Solanick

Plushanski

Kile

Mazzara

Yarasavage

Bonnice

Giangrieco/Trecoske

Baker

Frystak

Ricci

Susquehanna County

Wyoming County

Williams Pipeline – interconnects with Millennium and Tennessee pipelines

Tennessee Pipeline

Penn Virginia pipeline with connection to Transco

5,000 net acres Productive capacity of ~80 MMcf/d net 95% of acreage HBP’d on 1,000’ spacing Focus on operational efficiencies and cost control Limit production when local gas prices are especially weak


Marcellus Shale NE Pennsylvania

jefferies 2015 energy conference · 11/12/2015 · 2015 energy conference carrizo oil & gas,...

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