Filed by: Callon Petroleum Company Pursuant to Rule 425 under the Securities Act of 1933 and deemed filed pursuant to 14a-12 under the Securities Exchange Act of 1934 Subject Company: Carrizo Oil & Gas, Inc. Commission File No.: 000-29187-87 Set forth below is a copy of the press release and related presentation material relating to Callon Petroleum Company’s second quarter 2019 results: Callon Petroleum Company Announces Second Quarter 2019 Results HOUSTON, TX (August 6, 2019) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three and six months ended June 30, 2019. Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the “Presentations” page within the Investors section of the site. Second Quarter and Recent Highlights • Increased production by 40% year-over-year to 40.5 Mboe/d (77% oil) • Generated an operating margin of $36.11 per Boe, a sequential increase of over 10% • Reduced capital spending by $25 million during the second quarter, while placing approximately five additional net wells on production compared to the first quarter of 2019 • Recently placed on production the first multi-zone mega-pad employing simultaneous operations in the Delaware Basin with an average cost per lateral foot below 2020 targeted synergy levels • Closed the divestiture of the Southern Midland Basin assets for net cash proceeds at closing of $245 million • Completed the redemption of Callon preferred stock in the amount of $73 million, reducing annual dividend obligations by more than $7 million • Announced the strategic acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in an all-stock transaction valued at $3.2 billion “Our team’s performance continued to exceed expectations during the second quarter with stronger production and lower capital spending than forecasted. We remain on track to meet all of the goals that we laid out for the market back in February while delivering on a seamless integration process to cement a highly accretive acquisition opportunity that will benefit shareholders of both Callon and Carrizo. Our operational efficiency in the Midland Basin during the second quarter and successful completion of our first Delaware mega-pad project are emblematic of the value creation that underpins the strategic rationale in combining these two high performing companies,” commented Joe Gatto, Callon’s President and Chief Executive Officer. He continued, “We are steadfast in our commitment to accelerating the achievement of our core goals of boosting returns on invested capital, reducing leverage, generating sustainable free cash flow growth and improving the overall long-term outlook for our shareholders. With this strategic combination, which will be enhanced by the eminently achievable, tangible synergies identified, we will unlock significant value for shareholders in the near term as the highly efficient and sustainable development program we have outlined advances all of our goals. We are very pleased with our integration progress and equally excited about the tremendous value proposition created by merging our two organizations.” Operations Update At June 30, 2019, we had 487 gross (330.2 net) horizontal wells producing in the Permian Basin. Net daily production for the three months ended June 30, 2019 grew 40% to 40.5 Mboe/d (77% oil), at the top of the previously announced range of expectations (provided in the July 15, 2019 press release), as compared to the same period of 2018. For the three months ended June 30, 2019, we drilled 15 gross (14.3 net) horizontal wells, and placed a combined 18 gross (15.9 net) horizontal wells on production. Almost all of the wells were focused in the Midland Basin and included two six-well projects targeting three development zones that were placed on line under budget due to sustained, realized capital efficiencies. As part of our larger scale development model in the Midland Basin, a five well project in central Howard County achieved an average peak IP-30 rate of 1,346 Boe/d (91% oil), equating to 155 Boe/d per lateral foot. In addition, a two-well pad in the Delaware was placed on line, targeting co-development of the 2nd Bone Spring Shale and Lower Wolfcamp A.

Additional activity during the quarter in the Delaware Basin was focused on the completion of our first large scale development project, involving co-development of two Wolfcamp A flow units and the Wolfcamp B. Significant improvements in drilling and completion costs resulted in an average total well cost of less than $1,100 per lateral foot. These savings were realized through highly efficient simultaneous drilling and completion operation techniques that will be the focal point of the 2020 capital development program across the pro forma asset portfolio. In addition, water sourcing for the completion operations utilized over 1.6 million barrels from our Delaware recycling facilities, resulting in significant savings versus traditional sourcing methods. The wells from this project were recently placed on flow back and are in the early stages of production. Callon has reduced its number of active drilling rigs from six to four and is running a single completion crew after building a substantial inventory of drilled, uncompleted locations, in accordance with the previously communicated capital program expectations. In addition, the field optimization project initiated during the first quarter of 2019 in the Delaware Basin has been completed and all associated wells have been returned to production. Capital Expenditures For the six months ended June 30, 2019, we incurred $133.5 million in operational capital expenditures (including other items) on an accrual basis as compared to $155.2 million in the first quarter of 2019, representing a decrease of 14%. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands): Three Months Ended June 30, 2019 Operational Capitalized Capitalized Total Capital Capital (a) Interest G&A Expenditures Cash basis (b) $ 138,018 $ 21,962 $ 6,239 $ 166,219 Timing adjustments (c) (4,547) (3,225) — (7,772) Non-cash items — — 2,207 2,207 Accrual basis $ 133,471 $ 18,737 $ 8,446 $ 160,654 (a) Includes seismic, land and other items. (b) Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count. (c) Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.

Operating and Financial Results The following table presents summary information for the periods indicated: Three Months Ended June 30, 2019 March 31, 2019 June 30, 2018 Net production Oil (MBbls) 2,848 2,858 1,995 Natural gas (MMcf) 5,031 4,619 3,839 Total (Mboe) 3,687 3,628 2,635 Average daily production (Boe/d) 40,516 40,311 28,954 % oil (Boe basis) 77% 79% 76% Oil and natural gas revenues (in thousands) Oil revenue $ 160,728 $ 141,098 $ 122,613 Natural gas revenue 6,324 11,949 14,462 Total revenue 167,052 153,047 137,075 Impact of settled derivatives (1,157) (290) (7,980) Adjusted Total Revenue (i) $ 165,895 $ 152,757 $ 129,095 Average realized sales price (excluding impact of settled derivatives) Oil (per Bbl) $ 56.44 $ 49.37 $ 61.46 Natural gas (per Mcf) 1.26 2.59 3.77 Total (per BOE) 45.31 42.18 52.02 Average realized sales price (including impact of settled derivatives) Oil (per Bbl) $ 54.87 $ 48.83 $ 57.38 Natural gas (per Mcf) 1.91 2.86 3.81 Total (per BOE) 44.99 42.11 48.99 Additional per BOE data Sales price (a) $ 45.31 $ 42.18 $ 52.02 Lease operating expense 6.18 6.63 4.99 Production taxes 3.02 2.98 2.86 Operating margin $ 36.11 $ 32.57 $ 44.17 Depletion, depreciation and amortization $ 17.07 $ 16.47 $ 14.70 Adjusted G&A (b) Cash component (c) $ 2.42 $ 2.28 $ 2.69 Non-cash component 0.68 0.44 0.64 (a) Excludes the impact of settled derivatives. (b) Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. (c) Excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization. Total Revenue. For the quarter ended June 30, 2019, Callon reported total revenue of $167.1 million and total revenue including settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $165.9 million, including the impact of a $1.2 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company’s total operating revenue. Average daily production for the quarter was 40.5 Mboe/d compared to average daily production of 40.3 Mboe/d in the first quarter of 2019. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended June 30, 2019, the net gain (loss) on commodity derivative instruments includes the following: Three Months Ended June 30, 2019 In Thousands Per Unit Oil derivatives Net gain (loss) on settlements $ (4,461) $ (1.57) Net gain (loss) on fair value adjustments 13,310 Total gain (loss) on oil derivatives 8,849 Natural gas derivatives Net gain (loss) on settlements 3,304 $ 0.65 Net gain (loss) on fair value adjustments (1,430) Total gain (loss) on natural gas derivatives 1,874 Total commodity derivatives Net gain (loss) on settlements (1,157) $ (0.32) Net gain (loss) on fair value adjustments 11,880 Total gain (loss) on total commodity derivatives $ 10,723 Lease Operating Expenses, including workover (“LOE”). LOE per Boe for the three months ended June 30, 2019 was $6.18 per Boe, compared to LOE of $6.63 per Boe in the first quarter of 2019. The decrease on a per unit basis was attributable to a reduction in maintenance activities and increased water recycling, which lowered our water disposal costs compared to the previous period. Production Taxes, including ad valorem taxes. Production taxes were $3.02 per Boe for the three months ended June 30, 2019, representing approximately 6.7% of total revenue before the impact of derivative settlements. The incremental increase as compared to the first quarter of 2019 and second quarter of 2018 is due to an increase in ad valorem taxes based upon a higher valuation of our oil and gas properties by the taxing jurisdictions, resulting from an increased number of producing wells in the current period, as a result of our horizontal drilling program and acquisition efforts. Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended June 30, 2019 was $17.07 per Boe compared to $16.47 per Boe in the first quarter of 2019. The decrease is partially attributed to recent dispositions with a lower relative cost per BOE. General and Administrative (“G&A”). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A”, a non-GAAP measure(i)) was $11.4 million, or $3.10 per Boe, for the three months ended June 30, 2019 compared to $9.9 million, or $2.72 per Boe, for the first quarter of 2019. The cash component of Adjusted G&A was $8.9 million, or $2.42 per Boe, for the three months ended June 30, 2019 compared to $8.3 million, or $2.28 per Boe, for the first quarter of 2019. For the three months ended June 30, 2019, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share- based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands): Three Months Ended June 30, 2019 Total G&A expense $ 10,564 Change in the fair value of liability share-based awards (non-cash) 859 Adjusted G&A – total 11,423 Restricted stock share-based compensation (non-cash) (1,687) Corporate depreciation & amortization (non-cash) (807) Adjusted G&A – cash component $ 8,929 Income tax expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded an income tax expense of $16.7 million for the three months ended June 30, 2019, compared to income tax benefit of $5.1 million for the three months ended March 31, 2019. The change in income tax expense (benefit) is based upon net income (loss) generated in the respective periods.

Reaffirmed 2019 Guidance (stand alone Callon) There is no change to the Company’s previously updated full year guidance (provided June 13, 2019), which accounted for the impact of the sale of non-core assets and an announced acreage trade. This reaffirmed guidance does not take into effect the Carrizo merger, which is expected to close in the fourth quarter, subject to shareholder and regulatory approvals. Second Quarter First Half Reaffirmed Full Year 2019 Actual 2019 Actual 2019 Guidance Total production (Mboe/d) 40.5 40.4 38.0 - 39.5 % oil 77% 78% 78% - 79% Income statement expenses (per Boe) LOE, including workovers $6.18 $6.40 $5.50 - $6.50 Production taxes, including ad valorem (% unhedged revenue) 7% 7% 7% Adjusted G&A: cash component (a) $2.42 $2.35 $2.00 - $2.50 Adjusted G&A: non-cash component (b) $0.68 $0.56 $0.50 - $1.00 Cash interest expense (c) $0.00 $0.00 $0.00 Effective income tax rate 23% 24% 22% Capital expenditures ($MM, accrual basis) Total operational (d) $133 $289 $495 - $520 Capitalized interest and G&A expenses $27 $58 $100 - $105 Net operated horizontal wells placed on production 16 27 47 - 49 (a) Excludes stock-based compensation and corporate depreciation and amortization. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. (b) Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. (c) All cash interest expense anticipated to be capitalized. (d) Includes facilities, equipment, seismic, land and other items. Excludes capitalized expenses.

Hedge Portfolio Summary The following table summarizes our open derivative positions as of June 30, 2019: For the Remainder For the Full Year For the Full Year Oil contracts (WTI) of 2019 of 2020 of 2021 Puts Total volume (Bbls) 460,000 — — Weighted average price per Bbl $ 65.00 $ — $ — Put spreads Total volume (Bbls) 460,000 — — Weighted average price per Bbl Floor (long put) $ 65.00 $ — $ — Floor (short put) $ 42.50 $ — $ — Collar contracts with short puts (three-way collars) Total volume (Bbls) 2,392,000 3,294,000 — Weighted average price per Bbl Ceiling (short call) $ 67.46 $ 65.72 $ — Floor (long put) $ 56.54 $ 55.69 $ — Floor (short put) $ 43.65 $ 44.47 $ — Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 4,137,500 4,576,000 1,095,000 Weighted average price per Bbl $ (2.64) $ (1.29) $ 1.00 Oil contracts (Argus Houston MEH basis differential) Swap contracts Total volume (Bbls) — 552,000 — Weighted average price per Bbl $ — $ 3.30 $ — Natural gas contracts (Henry Hub) Collar contracts (two-way collars) Total volume (MMBtu) 1,196,000 — — Weighted average price per MMBtu Ceiling (short call) $ 3.50 $ — $ — Floor (long put) $ 3.13 $ — $ — Swap contracts Total volume (MMBtu) 1,397,000 — — Weighted average price per MMBtu $ 2.89 $ — $ — Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 4,232,000 4,758,000 — Weighted average price per MMBtu $ (1.18) $ (1.12) $ —

Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $53.4 million for the three months ended June 30, 2019 and Adjusted Income available to common shareholders of $41.3 million, or $0.18 per fully diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income available to common stockholders to reflect our theoretical tax provision for prior period quarters as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company’s income available to common stockholders to Adjusted Income and the Company’s net income to Adjusted EBITDA(i), a non-GAAP financial measure, (in thousands): Three Months Ended June 30, 2019 March 31, 2019 June 30, 2018 Income (loss) available to common stockholders $ 53,357 $ (21,367) $ 48,650 (Gain) loss on derivatives, net of settlements (15,193) 66,970 8,572 Change in the fair value of share-based awards (850) 1,881 (463) Other operating expense 770 — — Settled share-based awards — 3,024 — Tax effect on adjustments above 3,207 (15,094) (1,703) Change in valuation allowance — — (10,562) Adjusted Income (i) $ 41,291 $ 35,414 $ 44,494 Adjusted Income per fully diluted common share (i) $ 0.18 $ 0.16 $ 0.21 Three Months Ended June 30, 2019 March 31, 2019 June 30, 2018 Net income (loss) $ 55,180 $ (19,543) $ 50,474 (Gain) loss on derivatives, net of settlements (15,193) 66,970 8,572 Non-cash stock-based compensation expense 904 3,402 1,164 Settled share-based awards — 3,024 — Other operating expense 935 157 1,767 Income tax (benefit) expense 16,691 (5,149) 481 Interest expense 741 738 594 Depreciation, depletion and amortization 64,374 60,672 39,387 Accretion expense 216 241 206 Adjusted EBITDA (i) $ 123,848 $ 110,512 $ 102,645

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended June 30, 2019 was $122.9 million and is reconciled to operating cash flow in the following table (in thousands): Three Months Ended June 30, 2019 March 31, 2019 June 30, 2018 Cash flows from operating activities: Net income (loss) $ 55,180 $ (19,543) $ 50,474 Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization 64,374 60,672 39,387 Accretion expense 216 241 206 Amortization of non-cash debt related items 741 738 588 Deferred income tax (benefit) expense 16,691 (5,149) 481 (Gain) loss on derivatives, net of settlements (15,193) 66,970 8,572 (Gain) loss on sale of other property and equipment 21 28 22 Non-cash expense related to equity share-based awards 1,754 4,545 1,627 Change in the fair value of liability share-based awards (850) 1,881 (463) Discretionary cash flow (i) $ 122,934 $ 110,383 $ 100,894 Changes in working capital 27,789 (33,864) 8,978 Payments to settle asset retirement obligations (107) (664) (207) Payments to settle vested liability share-based awards (129) (1,296) (1,901) Net cash provided by operating activities $ 150,487 $ 74,559 $ 107,764

Callon Petroleum Company Consolidated Balance Sheets (in thousands, except par and per share data) June 30, 2019 December 31, 2018 ASSETS Unaudited Current assets: Cash and cash equivalents $ 16,052 $ 16,051 Accounts receivable 93,039 131,720 Fair value of derivatives 13,164 65,114 Other current assets 15,841 9,740 Total current assets 138,096 222,625 Oil and natural gas properties, full cost accounting method: Evaluated properties 4,665,761 4,585,020 Less accumulated depreciation, depletion, amortization and impairment (2,399,886) (2,270,675) Evaluated oil and natural gas properties, net 2,265,875 2,314,345 Unevaluated properties 1,429,624 1,404,513 Total oil and natural gas properties, net 3,695,499 3,718,858 Operating lease right-of-use assets 31,904 — Other property and equipment, net 23,363 21,901 Restricted investments 3,468 3,424 Deferred financing costs 5,427 6,087 Fair value of derivatives 11,679 — Other assets, net 6,061 6,278 Total assets $ 3,915,497 $ 3,979,173 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued liabilities $ 221,452 $ 261,184 Operating lease liabilities 24,141 — Accrued interest 22,695 24,665 Cash-settleable restricted stock unit awards 819 1,390 Asset retirement obligations 3,103 3,887 Fair value of derivatives 17,251 10,480 Other current liabilities 2,472 13,310 Total current liabilities 291,933 314,916 Senior secured revolving credit facility 105,000 200,000 6.125% senior unsecured notes due 2024 596,154 595,788 6.375% senior unsecured notes due 2026 394,106 393,685 Operating lease liabilities 7,680 — Asset retirement obligations 9,315 10,405 Cash-settleable restricted stock unit awards 2,568 2,067 Deferred tax liability 21,106 9,564 Fair value of derivatives 3,663 7,440 Other long-term liabilities 100 100 Total liabilities 1,431,625 1,533,965 Commitments and contingencies Stockholders’ equity: Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding 15 15 Common stock, $0.01 par value, 300,000,000 shares authorized; 228,263,955 and 227,582,575 shares outstanding, respectively 2,283 2,276 Capital in excess of par value 2,483,945 2,477,278 Accumulated deficit (2,371) (34,361) Total stockholders’ equity 2,483,872 2,445,208 Total liabilities and stockholders’ equity $ 3,915,497 $ 3,979,173

Callon Petroleum Company Consolidated Statements of Operations (Unaudited; in thousands, except per share data) Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Operating revenues: Oil sales $ 160,728 $ 122,613 $ 301,826 $ 237,898 Natural gas sales 6,324 14,462 18,273 26,617 Total operating revenues 167,052 137,075 320,099 264,515 Operating expenses: Lease operating expenses 22,776 13,141 46,843 26,179 Production taxes 11,131 7,539 21,944 16,002 Depreciation, depletion and amortization 62,921 38,733 122,688 74,151 General and administrative 10,564 8,289 22,317 17,057 Settled share-based awards — — 3,024 — Accretion expense 216 206 457 424 Other operating expense 935 1,767 1,092 2,315 Total operating expenses 108,543 69,675 218,365 136,128 Income from operations 58,509 67,400 101,734 128,387 Other (income) expenses: Interest expense, net of capitalized amounts 741 594 1,479 1,053 (Gain) loss on derivative contracts (14,036) 16,554 53,224 21,036 Other income (67) (703) (148) (914) Total other (income) expense (13,362) 16,445 54,555 21,175 Income (loss) before income taxes 71,871 50,955 47,179 107,212 Income tax (benefit) expense 16,691 481 11,542 976 Net income (loss) 55,180 50,474 35,637 106,236 Preferred stock dividends (1,823) (1,824) (3,647) (3,647) Income (loss) available to common stockholders $ 53,357 $ 48,650 $ 31,990 $ 102,589 Income (loss) per common share: Basic $ 0.23 $ 0.23 $ 0.14 $ 0.50 Diluted $ 0.23 $ 0.23 $ 0.14 $ 0.50 Weighted average common shares outstanding: Basic 228,051 210,698 227,917 206,309 Diluted 228,411 211,465 228,599 207,027

Callon Petroleum Company Consolidated Statements of Cash Flows (Unaudited; in thousands) Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Cash flows from operating activities: Net income (loss) $ 55,180 $ 50,474 $ 35,637 $ 106,236 Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization 64,374 39,387 125,046 75,453 Accretion expense 216 206 457 424 Amortization of non-cash debt related items 741 588 1,479 1,041 Deferred income tax (benefit) expense 16,691 481 11,542 976 (Gain) loss on derivatives, net of settlements (15,193) 8,572 51,777 4,594 Loss on sale of other property and equipment 21 22 49 22 Non-cash expense related to equity share-based awards 1,754 1,627 6,299 2,758 Change in the fair value of liability share-based awards (850) (463) 1,031 549 Payments to settle asset retirement obligations (107) (207) (771) (573) Payments for cash-settled restricted stock unit awards (129) (1,901) (1,425) (4,990) Changes in current assets and liabilities: Accounts receivable 44,071 10,447 38,681 2,380 Other current assets (3,807) (5,611) (6,101) (5,550) Current liabilities (10,251) 4,123 (36,254) 17,061 Other (2,224) 19 (2,401) (402) Net cash provided by operating activities 150,487 107,764 225,046 199,979 Cash flows from investing activities: Capital expenditures (166,219) (187,040) (359,430) (298,370) Acquisitions (11,423) (6,469) (39,370) (45,392) Acquisition deposit — (28,500) — (27,600) Proceeds from sale of assets 260,417 3,077 274,296 3,077 Net cash provided by (used in) investing activities 82,775 (218,932) (124,504) (368,285) Cash flows from financing activities: Borrowings on senior secured revolving credit facility 140,000 85,000 360,000 165,000 Payments on senior secured revolving credit facility (365,000) (160,000) (455,000) (190,000) Issuance of 6.375% senior unsecured notes due 2026 — 400,000 — 400,000 Issuance of common stock — 288,357 — 288,357 Payment of preferred stock dividends (1,823) (1,824) (3,647) (3,647) Payment of deferred financing costs (31) (8,664) (31) (8,664) Tax withholdings related to restricted stock units (833) (1,028) (1,858) (1,589) Other financing activities (5) — (5) — Net cash provided by (used in) financing activities (227,692) 601,841 (100,541) 649,457 Net change in cash and cash equivalents 5,570 490,673 1 481,151 Balance, beginning of period 10,482 18,473 16,051 27,995 Balance, end of period $ 16,052 $ 509,146 $ 16,052 $ 509,146

Non-GAAP Financial Measures and Reconciliations This news release refers to non-GAAP financial measures such as “Discretionary Cash Flow,” “Adjusted G&A,” “Adjusted Income,” “Adjusted EBITDA” and “Adjusted Total Revenue.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. • Callon believes that the non-GAAP measure of discretionary cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income. • Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans, as well as non- cash corporate depreciation and amortization expense. Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table here within details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A. • Callon believes that the non-GAAP measure of Adjusted Income available to common shareholders (“Adjusted Income”) and Adjusted Income per fully diluted common share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided here within. • Callon calculates adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation accretion expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that Adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA presented may not be comparable to similarly titled measures of other companies. • Callon believes that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues.

Earnings Call Information The Company will host a conference call on Wednesday, August 7, 2019, to discuss second quarter 2019 financial and operating results. Please join Callon Petroleum Company via the Internet for a webcast of the conference call: Date/Time: Wednesday, August 7, 2019, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time) Webcast: Select “IR Calendar” under the “Investors” section of the website: www.callon.com. Presentation Slides: Select “Presentations” under the “Investors” section of the website: www.callon.com. Alternatively, you may join by telephone using the following numbers: Toll Free: 1-888-317-6003 Canada Toll Free: 1-866-284-3684 International: 1-412-317-6061 Access code: 9809640 An archive of the conference call webcast will be available at www.callon.com under the “Investors” section of the website. About Callon Petroleum Company Callon Petroleum Company is an independent energy company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin in West Texas. This news release is posted on the Company’s website at www.callon.com and will be archived there for subsequent review under the “News” link on the top of the homepage. No Offer or Solicitation Communications in this news release do not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval with respect to the proposed transaction or otherwise, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. Communication in this news release do not constitute a notice of redemption with respect to or an offer to purchase or sell (or the solicitation of an offer to purchase or sell) any preferred stock of Carrizo. Additional Information and Where to Find It In connection with the proposed transaction, Callon and Carrizo intend to file materials with the Securities and Exchange Commission (the “SEC”), including a Registration Statement on Form S-4 of Callon (the “Registration Statement”) that will include a joint proxy statement of Callon and Carrizo that also constitutes a prospectus of Callon. After the Registration Statement is declared effective by the SEC, Callon and Carrizo intend to mail a definitive proxy statement/prospectus to stockholders of Callon and shareholders of Carrizo. This news release is not a substitute for the joint proxy statement/prospectus or the Registration Statement or for any other document that Callon or Carrizo may file the SEC and send to Callon’s stockholders and/or Carrizo’s shareholders in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF CALLON AND CARRIZO ARE URGED TO READ THE REGISTRATION STATEMENT AND JOINT PROXY STATEMENT/PROSPECTUS, AS EACH MAY BE AMENDED OR SUPPLEMENTED FROM TIME TO TIME, AND OTHER RELEVANT DOCUMENTS FILED BY CALLON AND CARRIZO WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CALLON, CARRIZO AND THE PROPOSED TRANSACTION. Investors will be able to obtain free copies of the Registration Statement and joint proxy statement/prospectus, as each may be amended from time to time, and other relevant documents filed by Callon and Carrizo with the SEC (when they become available) through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by Callon will be available free of charge from Callon’s website at www.callon.com under the “Investors” tab or by contacting Callon’s Investor Relations Department at (281) 589-5200 or IR@callon.com. Copies of documents filed with the SEC by Carrizo will be available free of charge from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab or by contacting Carrizo’s Investor Relations Department at (713) 328-1055 or IR@carrizo.com.

Participants in the Proxy Solicitation Callon, Carrizo and their respective directors and certain of their executive officers and other members of management and employees may be deemed, under SEC rules, to be participants in the solicitation of proxies from Callon’s stockholders and Carrizo’s shareholders in connection with the proposed transaction. Information regarding the executive officers and directors of Callon is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on March 27, 2019. Information regarding the executive officers and directors of Carrizo is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on April 2, 2019. Additional information regarding the persons who may be deemed participants and their direct and indirect interests, by security holdings or otherwise, will be set forth in the Registration Statement and joint proxy statement/ prospectus and other materials when they are filed with the SEC in connection with the proposed transaction. Free copies of these documents may be obtained as described in the paragraphs above. Cautionary Statement Regarding Forward Looking Statements Certain statements in this news release concerning the proposed transaction, including any statements regarding the expected timetable for completing the proposed Carrizo transaction, the results, effects, benefits and synergies of the proposed transaction, future opportunities for the combined company, future financial performance and condition, guidance and any other statements regarding Callon’s or Carrizo’s future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts are “forward-looking” statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “anticipate,” “likely” “plan,” “positioned,” “strategy,” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve significant risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to, failure to obtain the required votes of Callon’s stockholders or Carrizo’s shareholders to approve the transaction and related matters; whether any redemption of Carrizo’s preferred stock will be necessary or will occur prior to the closing of the transaction; the risk that a condition to closing of the proposed transaction may not be satisfied, that either party may terminate the merger agreement or that the closing of the proposed transaction might be delayed or not occur at all; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; the diversion of management time on transaction-related issues; the ultimate timing, outcome and results of integrating the operations of Callon and Carrizo; the effects of the business combination of Callon and Carrizo, including the combined company’s future financial condition, results of operations, strategy and plans; the ability of the combined company to realize anticipated synergies in the timeframe expected or at all; changes in capital markets and the ability of the combined company to finance operations in the manner expected; regulatory approval of the transaction; the effects of commodity prices; and the risks of oil and gas activities. Expectations regarding business outlook, including changes in revenue, pricing, capital expenditures, cash flow generation, strategies for our operations, oil and natural gas market conditions, legal, economic and regulatory conditions, and environmental matters are only forecasts regarding these matters. Additional factors that could cause results to differ materially from those described above can be found in Callon’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Reports on Form 10-Q for the quarter ended March 31, 2019 and quarter ended June 30, 2019, each of which is on file with the SEC and available from Callon’s website at www.callon.com under the “Investors” tab, and in other documents Callon files with the SEC, and in Carrizo’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, each of which is on file with the SEC and available from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab, and in other documents Carrizo files with the SEC. All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither Callon nor Carrizo assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

Contact Information Mark Brewer Director of Investor Relations Callon Petroleum Company ir@callon.com 1-281-589-5200

2nd QUARTER 2019 EARNINGS August 6, 2019

IMPORTANT DISCLOSURES No Offer or Solicitation Communications in this presentation do not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval with respect to the proposed transaction or otherwise, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. Communication in this presentation do not constitute a notice of redemption with respect to or an offer to purchase or sell (or the solicitation of an offer to purchase or sell) any preferred stock of Carrizo Oil & Gas, Inc. Additional Information and Where to Find It In connection with the proposed transaction, Callon Petroleum Company (“Callon”) and Carrizo intend to file materials with the Securities and Exchange Commission (the “SEC”), including a Registration Statement on Form S-4 of Callon (the “Registration Statement”) that will include a joint proxy statement of Callon and Carrizo that also constitutes a prospectus of Callon. After the Registration Statement is declared effective by the SEC, Callon and Carrizo intend to mail a definitive proxy statement/prospectus to stockholders of Callon and shareholders of Carrizo. This presentation is not a substitute for the joint proxy statement/prospectus or the Registration Statement or for any other document that Callon or Carrizo may file with the Securities and Exchange Commission (the “SEC”) and send to Callon’s stockholders and/or Carrizo’s shareholders in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF CALLON AND CARRIZO ARE URGED TO READ THE REGISTRATION STATEMENT AND JOINT PROXY STATEMENT/PROSPECTUS, AS EACH MAY BE AMENDED OR SUPPLEMENTED FROM TIME TO TIME, AND OTHER RELEVANT DOCUMENTS FILED BY CALLON AND CARRIZO WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CALLON, CARRIZO AND THE PROPOSED TRANSACTION. Investors will be able to obtain free copies of the Registration Statement and joint proxy statement/prospectus, as each may be amended from time to time, and other relevant documents filed by Callon and Carrizo with the SEC (when they become available) through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by Callon will be available free of charge from Callon’s website at www.callon.com under the “Investors” tab or by contacting Callon’s Investor Relations Department at (281) 589-5200 or IR@callon.com. Copies of documents filed with the SEC by Carrizo will be available free of charge from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab or by contacting Carrizo’s Investor Relations Department at (713) 328-1055 or IR@carrizo.com. Participants in the Proxy Solicitation Callon, Carrizo and their respective directors and certain of their executive officers and other members of management and employees may be deemed, under SEC rules, to be participants in the solicitation of proxies from Callon’s stockholders and Carrizo’s shareholders in connection with the proposed transaction. Information regarding the executive officers and directors of Callon is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on March 27, 2019. Information regarding the executive officers and directors of Carrizo is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on April 2, 2019. Additional information regarding the persons who may be deemed participants and their direct and indirect interests, by security holdings or otherwise, will be set forth in the Registration Statement and joint proxy statement/prospectus and other materials when they are filed with the SEC in connection with the proposed transaction. Free copies of these documents may be obtained as described in the paragraphs above. Cautionary Statement Regarding Forward-Looking Information Certain statements in this news release concerning the proposed transaction, including any statements regarding the expected timetable for completing the proposed transaction, the results, effects, benefits and synergies of the proposed Carrizo transaction, future opportunities for the combined company, future financial performance and condition, guidance and any other statements regarding Callon’s or Carrizo’s future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts are “forward-looking” statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “anticipate,” “likely” “plan,” “positioned,” “strategy,” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. The forward- looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve significant risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to, failure to obtain the required votes of Callon’s stockholders or Carrizo’s shareholders to approve the transaction and related matters; whether any redemption of Carrizo’s preferred stock will be necessary or will occur prior to the closing of the transaction; the risk that a condition to closing of the proposed transaction may not be satisfied, that either party may terminate the merger agreement or that the closing of the proposed transaction might be delayed or not occur at all; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; the diversion of management time on transaction-related issues; the ultimate timing, outcome and results of integrating the operations of Callon and Carrizo; the effects of the business combination of Callon and Carrizo, including the combined company’s future financial condition, results of operations, strategy and plans; the ability of the combined company to realize anticipated synergies in the timeframe expected or at all; changes in capital markets and the ability of the combined company to finance operations in the manner expected; regulatory approval of the transaction; the effects of commodity prices; and the risks of oil and gas activities. Expectations regarding business outlook, including changes in revenue, pricing, capital expenditures, cash flow generation, strategies for our operations, oil and natural gas market conditions, legal, economic and regulatory conditions, and environmental matters are only forecasts regarding these matters.

IMPORTANT DISCLOSURES (CONTINUED) Additional factors that could cause results to differ materially from those described above can be found in Callon’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Reports on Form 10-Q for the quarter ended March 31, 2019 and quarter ended June 30, 2019, each of which is on file with the SEC and available from Callon’s website at www.callon.com under the “Investors” tab, and in other documents Callon files with the SEC, and in Carrizo’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Reports on Form 10-Q for the quarter ended March 31, 2019 and June 30, 2019, each of which is on file with the SEC and available from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab, and in other documents Carrizo files with the SEC. All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither Callon nor Carrizo assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. Supplemental Non-GAAP Financial Measures This presentation includes non-GAAP measures, such as Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA, Net Debt to LQA Adjusted EBITDA, Total Liquidity, Discretionary Cash Flow and other measures identified as non- GAAP. Management also uses EBITDAX, which reflects EBITDA plus exploration and abandonment expense. Reconciliations are available in the Appendix. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation accretion expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation, and other operating expenses. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Net Debt to Last Twelve Months (“LTM”) Adjusted EBITDA and Net Debt to Last Quarter Annualized (“LQA”) Adjusted EBITDA are non-GAAP measures. The Company defines Net Debt to LTM Adjusted EBITDA as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s Adjusted EBITDA inclusive of annual pro-forma results from its acquisitions and disposition completed over the last twelve month period. The Company defines Net Debt to LQA Adjusted EBITDA as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s current quarter annualized Adjusted EBITDA inclusive of pro-forma results from its disposition completed in the current period. The Company presents these metrics to help evaluate its capital structure, financial leverage, and forward-looking cash profile. The Company believes that that these metrics are widely used by industry professionals, research and credit analysts, and lending and rating agencies in the evaluation of total leverage. Discretionary Cash Flow (“DCF”) is defined by the Company as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. The Company has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the company may not control and the cashflow effect may not be reflected the period in which the operating activities occurred. We believe discretionary cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income.

EXECUTION CONTINUED SEQUENTIAL ACHIEVEMENTS OPERATIONAL HIGHLIGHTS 41 DAILY PRODUCTION (Mboepd) . Larger projects yield meaningful cost reductions across the Permian . WildHorse 5-well pad (largest to date) averaged record D&C / 1,000’ of ~ $0.6 MM 40.5 with well performance aligned to older vintages . Delaware 6-well pad (largest to date) averaged record D&C / 1,000’ of ~ $1.1 MM, illustrating SIMOPS benefit with wells online at the end of July 40 1Q19 2Q19 . Delaware recycling capacity upgrade completed . Doubled daily water recycling capacity to 60K bwpd $40 OPERATING MARGIN ($/Boe) (1) . ~ 10% utilization rate of permitted capacity in the Delaware (2Q19) . 6-well Spur project utilized ~ 50% recycled water for fracs, with 2H19 program $35 targeted at ~ 80% . Completed Delaware optimization project improves uptime, reduces $30 LOE, and mitigates operational risk 1Q19 2Q19 . Executed on Ranger sale for $245 MM in net cash proceeds with $60 MM contingency payment upside $130 ADJ. EBITDA ($MM) (2) . Redeemed preferred stock, reducing overall financing costs $120 ACTUALS RELATIVE TO CONSENSUS (4) $110 2Q19 CONSENSUS 2Q19 ACTUAL $100 1Q19 2Q19 TOTAL PRODUCTION 40.0 40.5 (Mboepd) ADJ. EBITDA (2) 3.0x LEVERAGE (NET DEBT / LTM ADJ. EBITDA) (3) $116 $124 ($MM) CAPEX 2.5x $171 $161 ($MM) LOE 2.0x $6.41 $6.18 1Q19 2Q19 ($/Boe) 1. Based on unhedged revenue less LOE and production taxes on a Boe basis. 2. Based on CPE calculated Adjusted EBITDA, a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the Appendix. 3. Net Debt to LTM Adjusted EBITDA is a non-GAAP measure and is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents, divided by the Company’s Adjusted EBITDA inclusive of 4 annualized pro-forma results from its acquisitions and disposition completed over the last twelve month period. Please refer to the Appendix for reconciliation. 4. Based on Bloomberg consensus estimates as of 7/30/19.

2019 PLAN PROGRESSION AND CAPITAL EFFICIENCY 1H19 GROSS DUC BUILD COMPLETED TRANSITION TO LARGE PAD DEVELOPMENT 25 Currently running $400 Capital efficiency gains from larger pad 4 rigs after DUC wells development realized in 2H19 peaked in 2Q19 20 $300 15 $200 10 Gross DUC Inventory DUC Gross Operational Capital ($MM) CapitalOperational $100 5 0 $0 2017 2018 1Q19 2Q19 1H18 2H18 1H19 2H19E PROGRESSION TO FREE CASH FLOW (1) $0 $60 -$10 $50 -$20 $40 $/ -$30 Boe $30 $MM -$40 $20 -$50 DUC build -$60 $10 -$70 $0 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 DCF Less Operational Capex ($MM) Realized Unhedged Price ($/Boe) 1. Discretionary Cash Flow is a non-GAAP measure and is defined as net cash provided by operating activities before changes in working capital and payments to settle ARO and vested liability share-based awards. Please refer to the non-GAAP disclosures as well as the Appendix for reconciliation. Operational Capex based on accrual accounting. 5

CRZO TRANSACTION ADVANCES OUR STRATEGIC OBJECTIVES (1) INCREASE • Total corporate return focus drives shareholder value, competitive with other industries • Combined footprint will maintain top tier margins CROCI (2) • 2020 CROCI targeting > 15% SUSTAINABLE • Cash flow break-even reduced from ~ $55/Bbl (standalone) to ~ $50/Bbl in 2020 • At recent strip prices, generates > $100 million FCF next year FCF • 2021 FCF grows significantly at $55 WTI, drops break-even below $50 • Net Debt to LQA EBITDA (3) at June 30 2019, 2.3x (CPE stand-alone) REDUCE • FCF to pay down borrowings on new credit facility with opportunistic refinancing LEVERAGE opportunities • 2020 target leverage < 2.0x, additional upside from increased potential monetizations • Utilizes FCF generating asset base to increase development of core high value Permian LONG TERM asset base FOCUS • 2020 Delaware program has > 95% multi-well, multi-interval development utilizing SIMOPS, improving corporate capital efficiency 1. All estimates are based upon $55 WTI pricing and assuming closing of the CPE/CRZO transaction during 2019. 2. Cash Return on Invested Capital (“CROCI”) is defined as (GAAP cash flow from operations before changes in working capital + after-tax interest expense) / (average total debt + average stockholders’ equity). 3. Net Debt to LQA Adjusted EBITDA is a non-GAAP measure and is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s 6 current quarter annualized Adjusted EBITDA inclusive of pro-forma results from its disposition completed in the current period. Please refer to the Appendix for reconciliation.

“TEXAS STRONG”: CREATING THE PREMIER OILY MID-CAP COMPANY CAPITAL EFFICIENT OIL-WEIGHTED RETURNS CENTRALIZED IN TEXAS FCF YIELD COMPETITIVE ACROSS SECTORS AND PEERS DELAWARE - ATTRACTIVE FINANCIAL PROFILE WITH DELEVERAGING UPSIDE PERMIAN PERMIAN 2020E Capital Allocation: OPERATIONAL FLEXIBILITY AND PRICE ~50% DIVERSIFCATION PRO FORMA OVERVIEW 2Q19 production mboepd (1) 106.1 MIDLAND 2020E rigs ~ 9 - LTM Adj. EBITDA (2Q19) (2) $1.2 billion (LTM) YE18 SEC PV-10 ~ $7.0 billion FORD EAGLE YE18 SEC PD PV-10 ~ $4.4 billion 2020E Capital Allocation: PERMIAN 2020E Capital Allocation: Enterprise Value (3) ~ $4.9 billion ~25% ~25% ~200,000 Net Acres 1. Based on CPE actuals and CRZO pre-released guidance. 2. Based on CPE actuals and 2Q19 CRZO consensus estimates as of 7/31/19. 3. Based on 8/5/19 prices, 2Q19 CPE net debt and 1Q19 CRZO net debt, plus preferred. 7

PRO FORMA INVENTORY BALANCED WITH LONG TERM FOCUS PRO FORMA DELINEATED INVENTORY RANKED BY IRR (1) Delineated locations with > 25% IRR including facilities PRESERVING HIGH RETURN DELAWARE INVENTORY (2) OPTIMAL INVENTORY LIFE ACROSS PRO FORMA ASSETS Thoughtful HBP development aligned with CPE’s long-term EAGLE DELAWARE MIDLAND co-development and asset optimization strategy FORD Net Acres ~ 90,000 ~ 30,000 ~ 80,000 Intervals 7 5 1 Gross Operated ~ 1,250 ~ 650 ~ 600 PEERS CRZO Delineated Locations Average Lateral Ft 8,700 7,800 7,100 (Inventory) Inventory Years (3) ~ 17 Years ~ 10 Years WCA and Above Below WCA 1. Operated inventory shown; excludes locations with IRR <25%; assumes 1Q19 D&C costs plus 10% additional facilities; assumes internal Callon / Carrizo type curves as of 1Q19. Assumes oil pricing as follows: WTI: $55 / bbl flat; WTI-Midland differential: ($1.00) / bbl; LLS-WTI differential: +$3.00 / bbl; Brent-WTI differential: +$8.00 / bbl; assumes gas pricing as follows: HHUB: $2.75 / mmbtu flat ; HHUB-WAHA differential: ($1.50) / mmbtu for 2Q19-3Q19 and ($0.75) / mmbtu from 4Q19 onward; assumes NGL pricing as follows: $20 / bbl NGLs. 8 2. Source: Drilling info with peers including APC, AXAS, CDEV, CXO, DVN, EOG, FANG, JAG, NBL, OAS, OXY, PDCE, PE, ROSE, WPX, XEC. 3. Based on PF 2020 capital program pace.

LEADING SOUTHERN DELAWARE WELL PERFORMANCE (1) SOUTHERN DELAWARE WCA WELLS ACROSS PEERS WCA RESULTS BY OPERATOR (2017+) (2) 100% 90% 80% 70% 60% 50% 40% 30% 20% CPE Well Count and Production Distribution Plot P(x) Plot Distribution Production and Count Well 10% CRZO 0% Average 6 Month Cumulative Production Boe (20:1 Oil Gas Conversion) 20,000 18,000 16,000 Boe 14,000 12,000 10,000 8,000 (20:1 Conversion)(20:1 6,000 4,000 Average 6 Month Cumulative 6 Month Average 2,000 0 Peer 1 Peer 2 CRZO CPE Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer Peer 10 11 1. Source: All well data sourced from drilling info with wells drilled and completed by operator. 2. P50 represents the average well performance by each operator for Wolfcamp A wells brought online in the Southern Delaware from 2017-current and have at least 6 months of publicly available production data. 9

PRIMARY IDENTIFIED SYNERGIES: $100 - $125 MM PER YEAR 2020 SYNERGY ACHIEVEMENT LEVEL ESTIMATED TO BE 50% - 75% OF ANNUAL RUN RATE Corporate G&A Delaware D&C Cost Improved Permian Reductions Savings Production Uptime 2020 Synergy Target: 2020 Synergy Target: 2020 Synergy Target: 75% of annual run rate savings 5% reduction over 2019 1% increase in Permian field of $35 - $45 MM Delaware D&C / 1,000’ production uptime LTM Pro Forma G&A (1) 2019E D&C / 1,000’ 10% 2020 – 2021 Corporate ~ $160 MM $1.2 MM Wide Production CAGR 2020 Total G&A Reduction Target 2019 Combined Operational Eagle Ford Maintenance Mode ~ 20% Capital Budget Guidance (~ 40 mboepd) ~ $1.1 B Permian Production 2020 Delaware Capital X (~ 50% of planned spending) $/Boe uplift value ~ $35 - $40 (2) 2020 Synergy uplift: 2020 Synergy uplift: 2020 Synergy uplift: ~ $35 MM ~ $25 - $30 MM ~ $10 MM VALUE UPLIFT OF ~ $70 to $75 MILLION IN 2020 FOR PRIMARY SYNERGIES ONLY 1. LTM total pro forma G&A figures are based off accrual accounting and inclusive of all corporate G&A, including capitalized G&A for both companies 2. $/Boe uplift based on revenue benefit less severance taxes, ad valorem taxes, and variable LOE. 10

OPERATIONAL SYNERGIES: LARGE PROJECTS REDUCE CAPITAL COSTS DELAWARE D&C SYNERGY - 2020 TARGETS & 2019 PROGRESS SIMOPS SYNERGY CAPTURE $1.5 > 20% cycle time improvement for ~ 5%: 2020E D&C / 1,000’ savings both drilling and completions from SIMOPS $1.4 5 Rigs: 2020 PF Delaware program 6 1000 DelawareDrilling Efficiency (Feet perday) $25 MM - $30 MM: 2020 low risk synergies from larger pro forma project size 5 $1.3 750 4 $1.2 SIMOPS 3 500 D&C ($ 1,000’) /($ D&C $1.1 2 250 $1.0 Delaware Completion (Stages per day) per (Stages Completion Delaware 1 $0.9 0 0 2018 2019E 2020E Rag Run Pad Single Multi-Well SimOps PRIMARY OPERATIONAL SYNERGIES – D&C REDUCTION BREAKDOWN 2021 PERMIAN D&C SYNERGY TARGETS Description 2020 Comments 2021+ Comments . ~ 5% - 8%: 2021E D&C / 1,000’ savings . Based off 1Q19 and applied across entire Permian Preliminary PF CAPEX ~ $1.1 B ~$1.1 - $1.2 B capital program Delaware Basin Estimated Capital Allocation 50% 75% Permian Basin . Mega-pad development enhances drilling Only efficiency via learnings from first to last well in CAPEX Base for Synergy $525 - $575 MM $825 - $900 MM pad and fewer/shorter rig moves per year Delaware Basin D&C Synergy Guidance 5% 5% - 8% Permian Basin . SIMOPS via consistent utilization of multiple Only dedicated crews yields step-change in Scaled with activity D&C Synergy Target $25 - $30 MM 1H20 Phase-In $45 - $65 MM levels completion efficiencies 11

OPERATIONAL SYNERGIES: LARGE PROJECTS ACCELERATE RETURNS UPTIME SYNERGY BREAKDOWN UPTIME SYNERGY CASH FLOW IMPACT . ~ 1% production uplift across Permian in 2020 Description 2020 2021+ . Opportunity for uptime improvement to expand to ~ 2% over time, further compounded as production grows Estimated Permian uptime 1% 1% - 2% improvement . Uptime synergies driven by concentrated SIMOPS development and resulting cycle time efficiencies 700 - 750 800 – 1,800 Daily production uplift . Reduced offset frac impact benefits current production Boe/d Boe/d . Lower number of total wells impacted (1) . Shortened timeline to recover production Operating margin $35 - $40 / Boe $35 - $40 / Boe . Minimization of planned shut-ins via concentration of activity and reduce downtime as a result of faster cycle times Annual Cash Flow Impact ~ $10 MM ~ $10 - $20 MM BEST IN CLASS MARGINS OFFER DIFFERENTIATED UPTIME RETURNS FOR MODERATE AND SUSTAINABLE GROWTH (2) 25% JAG US Equity 20% MTDR US Equity 15% PE US Equity CPE PDCE US Equity WPX US Equity 10% PF CPE SM US Equity CRZO CDEV US Equity AXAS US Equity 5% QEP US Equity OAS US Equity LPI US Equity 0% 2020 Production Growth Estimates ProductionGrowth 2020 -5% $15 $20 $25 $30 $35 2Q19 Adj. EBITDA/BOE 1. $/Boe uplift based on revenue benefit less severance taxes, ad valorem taxes, and variable LOE. 2. Sourced from Bloomberg with 2Q19 EBITDA and production based on actuals and consensus estimates as of 8/2/19. 2020 consensus production growth based on estimates as of 8/2/19 with the exception of CPE and CRZO standalone at 7/12/19. 2Q19 CRZO production based on pre-release guidance. Bubble size based on 2Q19 production volumes. Peers include: AXAS, CDEV, JAG, LPI, MTDR, OAS, PE, PDCE, QEP, SM, and 12 WPX.

RISK MANAGEMENT AMID MACRO UNCERTAINTY RISK MANAGEMENT PHILOSOPHY MARKETING EFFORTS DIVERSIFY PRICING EXPOSURE . Hedge strategy 45 2Q21: ~ 40 mb/d gross CPE 40 Permian volumes linked to . Target 40 – 60% of production with focus on protecting cash flow MEH/International pricing . Link risk management tools to physical delivery points to avoid 35 dislocation 30 . Mix of collars and puts strategy provides upside participation 25 . Marketing strategy 20 . < 40% Midland pricing exposure (excluding CRZO Eagle Ford) 15 . Oil sales agreements are into local onshore markets and do not 10 rely on export capacity Gross CPE Volumes Linked to LinkedVolumes CPE Gross MEH/International Pricing (Mb/d) PricingMEH/International . Gas marketing agreements align the interest of buyer with CPE 5 for surety of movement 0 1Q20 1Q20 3Q20 2Q21 HISTORICAL OIL HEDGE POSITIONS 40,000 Swaps 3-Way Collar 2-Way Collar Def Prem Put Put Spread Unhedged Volumes 35,000 30,000 /d 25,000 Bbl 20,000 15,000 Cumulative 10,000 5,000 0 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 13

FINANCIAL STRENGTH KEY CORPORATE PRINCIPLES Prudent Financial and Generate Sustainable Reduce Leverage to Maintain Strong Liquidity Preserve Top-Tier Physical Risk Free Cash Flow Growth < 2.0x Position Operating Margins Management HIGHLIGHTS 2Q19 CPE CAPITALIZATION TABLE . Closed Ranger sale for net cash proceeds of $245 MM with 2Q19 $60 MM contingency upside Cash $16 . Redeemed 10% preferred stock early in 3Q Credit Facility $105 Senior Notes due 2024 600 . Upgraded by Moody’s to B1 with stable outlook and placed on CreditWatch Positive by S&P (current rating B) Senior Notes due 2026 400 Total Debt $1,105 . Expanded hedging and marketing arrangements to further Stockholders’ Equity 2,484 diversify price concentration risk Total Capitalization $3,589 . Forecast corporate-wide FCF in 4Q19 with recent CRZO Total Liquidity (1) $743 acquisition offering an accelerated path to FCF in 2020 Net Debt to LQA EBITDA (2) 2.3x . CRZO acquisition enhances opportunistic refinancing flexibility to reduce cost of capital over time PRO FORMA FREE CASH FLOW BREAKEVEN ~ $60 ~ $50 < $50 2019E 2020 Target 2021 Target 1. Based on current elected commitment amount. All figures are as of 6/30/2019 and reflect certain items, such as letters of credit, not specifically shown in the capitalization table. 2. Net Debt to LQA Adjusted EBITDA is a non-GAAP measure and is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s current quarter annualized Adjusted EBITDA inclusive of pro-forma results from its disposition completed in the current period. Please refer to the Appendix for reconciliation. 14

COMBINATION ACCELERATES STRATEGIC PATH Relentless Pursuit of Capital Efficiency Differentiated Oil and • Clear economic benefits of scaled development model Gas Investment across portfolio Combining Repeatable • Sustainable “life of field” development of substantial Growth with Leading inventory Full-Cycle Cost of Supply • Balance of cash conversion cycle times Sustainable Free Cash Flow Growth • Preservation of leading cash margins • Rationalization of corporate costs • Combination of relatively mature production profiles • Double-digit production growth within cash flow Improved Financial Profile • Accelerated free cash flow for near-term debt reduction • Large, diversified asset base with opportunities for pruning • Visibility to improved cost of capital 15

APPENDIX

OIL HEDGE PORTFOLIO (1) 3Q19 4Q19 2H19 1Q20 2Q20 3Q20 4Q20 FY 2020 FY 2021 NYMEX WTI (Bbl, $/Bbl) Swaps Total Volumes - - 273,000 273,000 276,000 276,000 1,098,000 - Total Daily Volumes - - 3,000 3,000 3,000 3,000 3,000 - Avg. Sw ap - - $ 56.17 $ 56.17 $ 56.17 $ 56.17 56.17 - Three-way Collars Total Volumes 1,196,000 1,196,000 2,392,000 819,000 819,000 828,000 828,000 3,294,000 - Total Daily Volumes 13,000 13,000 13,000 9,000 9,000 9,000 9,000 9,000 - Avg. Short Call Price $67.46 $67.46 $67.46 $65.72 $65.72 $65.72 $65.72 $65.72 - Avg. Long Put Price $56.54 $56.54 $56.54 $55.69 $55.69 $55.69 $55.69 $55.69 - Avg. Short Put Price $43.65 $43.65 $43.65 $44.47 $44.47 $44.47 $44.47 $44.47 - Avg. Premium Price ($0.09) ($0.09) ($0.09) $0.33 $0.33 $0.33 $0.33 $0.33 - Put Options Total Volumes 230,000 230,000 460,000 - - - - - - Total Daily Volumes 2,500 2,500 2,500 - - - - - - Avg. Long Put Price $65.00 $65.00 $65.00 - - - - - - Avg. Premium Price $6.44 $6.44 $6.44 - - - - - - Put Spreads Total Volumes 230,000 230,000 460,000 - - - - - - Total Daily Volumes 2,500 2,500 2,500 - - - - - - Avg. Long Put Price $65.00 $65.00 $65.00 - - - - - - Avg. Short Put Price $42.50 $42.50 $42.50 - - - - - - Avg. Premium Price $4.39 $4.39 $4.39 - - - - - - Total Volume Hedged (Bbl) 1,656,000 1,656,000 3,312,000 1,092,000 1,092,000 1,104,000 1,104,000 4,392,000 - Average Ceiling Price ($/Bbl) $67.46 $67.46 $67.46 $63.33 $63.33 $63.33 $63.33 $63.33 - Average Floor Price ($/Bbl) $58.89 $58.89 $58.89 $55.81 $55.81 $55.81 $55.81 $55.81 - MIDLAND-CUSHING DIFFERENTIAL (Bbls/$/Bbl) Swaps Total Volumes 1,961,500 2,176,000 4,137,500 1,092,000 1,092,000 1,196,000 1,196,000 4,576,000 1,095,000 Total Daily Volumes 21,321 23,652 22,486 12,000 12,000 13,000 13,000 12,503 3,000 Avg. Sw ap Price ($2.81) ($2.50) ($2.64) ($1.73) ($1.73) ($0.89) ($0.89) ($1.29) $1.00 MEGELLAN EAST HOUSTON DIFFERENTIAL (Bbls/$/Bbl) Swaps Total Volumes - - - - - 276,000 276,000 552,000 - Total Daily Volumes - - - - - 3,000 3,000 1,508 - Avg. Sw ap Price - - - - - $3.30 $3.30 $3.30 - 1. Hedge contracts as of 8/1/19. 17

GAS HEDGE PORTFOLIO (1) 3Q19 4Q19 2H19 1Q20 2Q20 3Q20 4Q20 FY 2020 FY 2021 NYMEX HENRY HUB (MMBtu, $/MMBtu) Swaps Total Volumes 1,242,000 155,000 1,397,000 - - - - - - Total Daily Volumes 13,500 1,685 7,592 - - - - - - Avg. Swap Price $2.89 $0.97 $1.93 - - - - - - Two-way Collars Total Volumes 598,000 598,000 1,196,000 - - - - - - Total Daily Volumes 6,500 6,500 6,500 - - - - - - Avg. Short Call Price $3.50 $3.50 $3.50 - - - - - - Avg. Put Price $3.13 $3.13 $3.13 - - - - - - Total Volume Hedged (MMBtu) 1,840,000 753,000 2,593,000 - - - - Average Ceiling Price ($/MMBtu) $3.09 $3.41 $3.25 - - - - Average Floor Price ($/MMBtu) $2.97 $3.09 $3.03 - - - - WAHA DIFFERENTIAL (MMBtu, $/MMBtu) Swaps Total Volumes 2,116,000 2,116,000 4,232,000 1,183,000 1,183,000 1,196,000 1,196,000 4,758,000 - Total Daily Volumes 23,000 23,000 23,000 13,000 13,000 13,000 13,000 13,000 - Avg. Swap Price ($1.18) ($1.18) ($1.18) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) - 1. Hedge contracts as of 8/1/19. 18

QUARTERLY CASH FLOW STATEMENT 2Q18 3Q18 4Q18 1Q19 2Q19 CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 50,474 $ 37,931 $ 156,194 $ (19,543) $ 55,180 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 39,387 48,977 60,301 60,672 64,374 Accretion expense 206 202 248 241 216 Amortization of non-cash debt related items 588 708 734 738 741 Deferred income tax (benefit) expense 481 1,487 5,647 (5,149) 16,691 (Gain) loss on derivatives, net of settlements 8,572 25,100 (105,512) 66,970 (15,193) (Gain) loss on sale of other property and equipment 22 (102) (64) 28 21 Non-cash expense related to equity share-based awards 1,627 1,708 1,823 4,545 1,754 Change in the fair value of liability share-based awards (463) 879 (1,053) 1,881 (850) Payments to settle asset retirement obligations (207) (507) (389) (664) (107) Payments for cash-settled restricted stock unit awards (1,901) - - (1,296) (129) Changes in current assets and liabilities: Accounts receivable 10,447 (56,764) 37,033 (5,390) 44,071 Other current assets (5,611) 3,885 (5,936) (2,294) (3,807) Current liabilities 4,123 47,741 9,510 (26,003) (10,251) Other 19 4,791 (6,897) (177) (2,224) Net cash provided by operating activities 107,764 116,036 151,639 74,559 150,487 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (187,040) (156,982) (155,821) (193,211) (166,219) Acquisitions (6,469) (550,592) (122,809) (27,947) (11,423) Acquisition deposit (28,500) 27,600 - - - Proceeds from sales of assets 3,077 5,249 683 13,879 260,417 Additions to other assets - - (3,100) - - Net cash provided by (used in) investing activities (218,932) (674,725) (281,047) (207,279) 82,775 CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on senior secured revolving credit facility 85,000 105,000 230,000 220,000 140,000 Payments on senior secured revolving credit facility (160,000) (40,000) (95,000) (90,000) (365,000) Issuance of 6.375% senior unsecured notes due 2026 400,000 - - - - Payment of deferred financing costs (8,664) (1,296) 530 - (31) Issuance of common stock 288,357 7 (376) - - Payment of preferred stock dividends (1,824) (1,823) (1,824) (1,824) (1,823) Tax withholdings related to restricted stock units (1,028) (216) - (1,025) (833) Other financing activities - - - - (5) Net cash provided by (used in) financing activities 601,841 61,672 133,330 127,151 (227,692) Net change in cash and cash equivalents 490,673 (497,017) 3,922 (5,569) 5,570 Balance, beginning of period 18,473 509,146 12,129 16,051 10,482 Balance, end of period $ 509,146 $ 12,129 $ 16,051 $ 10,482 $ 16,052 19

NON-GAAP RECONCILIATION (1) ADJUSTED EBITDA RECONCILIATION 2Q18 3Q18 4Q18 1Q19 2Q19 Net income (loss) $ 50,474 $ 37,931 $ 156,194 $ (19,543) $ 55,180 (Gain) loss on derivatives, net of settlements 8,572 25,100 (105,512) 66,970 (15,193) Non-cash stock-based compensation expense 1,164 2,587 770 3,402 904 Settled share-based awards - - - 3,024 - Other operating expense 1,767 1,435 1,333 157 935 Income tax (benefit) expense 481 1,487 5,647 (5,149) 16,691 Interest expense 594 711 735 738 741 Depreciation, depletion and amortization 39,387 48,977 60,301 60,672 64,374 Accretion expense 206 202 248 241 216 Adjusted EBITDA $ 102,645 $ 118,430 $ 119,716 $ 110,512 $ 123,848 LQA NET DEBT TO ADJUSTED EBITDA 2Q19 Senior secured revolving credit facility $ 105,000 6.125% senior unsecured notes due 2024 600,000 6.375% senior unsecured notes due 2026 400,000 Total principal outstanding 1,105,000 LESS: Unrestricted cash (pro forma) (16,052) Net Debt 1,088,948 Adjusted EBITDA 123,848 Pro forma adjustments (5,764) Adjusted EBITDA inclusive of pro forma adjustments 118,084 LQA Adjusted EBITDA $ 472,336 LQA Net debt to Adjusted EBITDA 2.3 DISCRETIONARY CASH FLOW RECONCILIATION 2Q18 3Q18 4Q18 1Q19 2Q19 Net cash provided by operating activities $ 107,764 $ 116,036 $ 151,639 $ 74,559 $ 150,487 Changes in working capital (8,978) 347 (33,710) 33,864 (27,789) Payments to settle asset retirement obligations 207 507 389 664 107 Payments for cash-settled restricted stock unit awards 1,901 - - 1,296 129 Discretionary cash flow $ 100,894 $ 116,890 $ 118,318 $ 110,383 $ 122,934 1. See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 20