CRZO

1Q 2019 Earnings PresentationMay 8, 2019

CRZO22

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, 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 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 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, 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.

CRZO33

1Q Overview

$0.47Above consensus expectations

$153MM

Above consensus expectations

$27/Boe

Driven by high-return Eagle Ford

62.0MBoe/d

Near high end of guidance

$14/Boe

At low end of guidance

Adjusted EPS Adjusted EBITDA Adjusted EBITDA Margin

Total Production Oil Production Total Operating Expense

40.7MBbls/d

Above high end of guidance

CRZO4

1Q D&C Spend 1Q Infrastructure Spend

Infrastructure Eagle Ford

Delaware Basin

2019 Development PlanOn Track to Hit Full-year Budget

$525-$575 MM Budget

Note: 2019 updated guidance provided May 7, 2019. Values represent midpoint of ranges.

~60%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

Eagl

e F

ord

De

law

are

Bas

inTo

tal C

om

pan

y1Q D&C Spend 1Q Infrastructure SpendEagle Ford InfrastructureDelaware Basin

CRZO5

0

5

10

15

20

25

30

35

40

2Q18 3Q18 4Q18 1Q19

No

. of

Wel

ls

Net Wells Drilled Net Wells Completed

Eagle Ford ShaleOperations Summary

0

10

20

30

40

50

2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19

MB

oe

/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 O

il Price

Mar

gin

($

/Bo

e)

Operating Margin Production/Ad Val Tax

Total LOE Average WTI Oil

Completed two large-scale multipad projects

Production currently ~17,000 Bbls/d gross

Continued to generate operational efficiencies

Achieved 10%-15% reduction in drilling and completion costs vs. 4Q18

Average well cost lowered to $3.9-$4.1 MM

CRZO6

Eagle Ford ShaleStrong 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

0

5

10

15

20

25

30

35

40

45

02,0004,0006,0008,000

10,00012,00014,00016,00018,00020,000

No

. of W

ells On

line

Bb

ls/d

Gross Oil Production

No. Wells Online

Pena

RPG

CRZO7

Eagle Ford ShaleProgram Focused on Multipad Projects

Irvin

Brown Trust

Arnold

AreaWell

CountTotal Frac

StagesAverage Lateral

Brown Trust 13 413 ~6,400 ft.

Irvin 14 481 ~6,900 ft.

Arnold 9 420 ~9,300 ft.

Upcoming Multipad Projects

CRZO8

$0

$10

$20

$30

$40

$50

$60

$70

$-

$10

$20

$30

$40

$50

$60

$70

2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19

WTI O

il Price

Mar

gin

($

/Bo

e)

Operating Margin Production/Ad Val Tax

Total LOE Average WTI Oil

0

2

4

6

8

10

2Q18 3Q18 4Q18 1Q19

No

. of

wel

ls

Net Wells Drilled Net Wells Completed

Delaware BasinOperations Summary

0

5

10

15

20

25

30

35

2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19

MB

oe

/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

>35% reduction in drilling cost per effective lateral foot compared to 4Q18 in Ford West

~25% reduction in average frac cost per stage compared to 3Q18

Average well cost lowered to $7.8-$8.2 MM

CRZO9 CRZO9

Delaware BasinConducting Cube Tests to Optimize Development

St. Clair Pad 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:

Increased stimulated rock volume (SRV)

Stress shadowing and frac sequencing to strongly influence frac geometry

Carbonates are effective frac barriers and will impact:

Well placement

Development planning

12H

WCABounded

WCABounded

11H

10H

11H

10H

12H

WCA

WCBUpper

WCB Lower

WCC

WCAUnbounded

WCBUUnbounded

WCBUBounded

WCBLUnbounded

WCBLBounded

WCBLBounded

WCCBounded

WCCUnbounded

Additional Completion Tests

CRZO10

Delaware BasinEncouraging Early Results from Initial Cube Test

0

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

MB

oe

Days on Production

WCA

WCB

WCC

0

2,000

4,000

6,000

8,000

10,000

12,000

Bo

e/d

Summary Highlights

Early peak rate of ~10,600 Boe/d

60% oil, 78% liquids

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 production22-stream production

Upcoming Cube Test

Dorothy-Sansom

7-well, 5-layer co-development test

3rd BS, WCA, WCBU, WCBL, WCC

Drilling operations have commenced

CRZO11

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

$/B

oe

LOE Breakdown

$7.54

Revenue Drivers

$7.34$6.77

$0

$10

$20

$30

$40

$50

2Q18 3Q18 4Q18 1Q19

$/B

oe

Adjusted EBITDA Margin Cash G&A

Production/Ad Val Tax LOE

Adjusted EBITDA Margin

1Q Highlights

$30

$35

$40

$45

$50

$55

5052545658606264666870

2Q18 3Q18 4Q18 1Q19

$/B

oe

MB

oe

/d

Production Unhedged Realized Price

$27.15 $27.41

SWDWorkover ExpenseRepairs/MaintenanceRental Equipment

ChemicalsTransport and Processing All Other Categories

$34.45 $35.14

$6.90

CRZO1212

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2019 2020 2021 2022May

2023April

2024 2025July

$M

M

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

2016 2017 2018 Target

Ne

t D

eb

t /

Ad

just

ed

EB

ITD

A

Historical Leverage Metrics1

Revolving Credit Facility$1.25 billion borrowing base commitment

6.25% Senior Unsecured Notes$650 million outstandingCurrently callable

8.25% Senior Unsecured Notes$250 million outstandingCallable on July 15, 2020

Corporate Credit RatingB1 (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 FocusFree Cash Flow Targeted for Debt Reduction

CRZO13

Protect cash flows

Hedging ProgramDisciplined 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

CRZO14

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

CRZO15 CRZO1515 CRZO15

1Q 2019

In thousands Per dilutedShare

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 adjusted for ordinary permanent differences.

CRZO16 CRZO1616 CRZO16

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 -- -- 910 --

Non-recurring and other (income) expense, net 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)