Carrizo Oil & Gas Inc. Announces Third Quarter Results

• Total production of 64,627 Boe/d, 17% above the third quarter of 2017 and above the high-end of the Company’s guidance range
• Crude oil production of 40,813 Bbls/d, 17% above the third quarter of 2017 and 8% above the second quarter of 2018
• Net income attributable to common shareholders of $76.1 million, or $0.85 per diluted share, and Net cash provided by operating activities of $189.4 million
• Adjusted net income attributable to common shareholders of $84.1 million, or $0.94 per diluted share, and Adjusted EBITDA of $209.0 million
• Additional strong Delaware Basin results from the Company’s Phantom and Ford West areas
• Increasing 2018 production guidance to 60,200-60,500 Boe/d from 58,700-60,100 Boe/d

Carrizo reported third quarter of 2018 net income attributable to common shareholders of $76.1 million, or $0.88 and $0.85 per basic and diluted share, respectively, compared to net income attributable to common shareholders of $5.6 million, or $0.07 per basic and diluted share, in the third quarter of 2017. The net income attributable to common shareholders for the third quarter of 2018 and the third quarter of 2017 include certain items typically excluded from published estimates by the investment community. Adjusted net income attributable to common shareholders, which excludes the impact of these items as described in the non-GAAP reconciliation tables included below, for the third quarter of 2018 was $84.1 million, or $0.94 per diluted share, compared to $26.7 million, or $0.33 per diluted share, in the third quarter of 2017.

For the third quarter of 2018, Adjusted EBITDA was $209.0 million. Adjusted EBITDA and the reconciliation to net income attributable to common shareholders and net cash provided by operating activities are presented in the non-GAAP reconciliation tables included below.

Production volumes during the third quarter of 2018 were 5,946 MBoe, or 64,627 Boe/d, an increase of 17% versus the third quarter of 2017. The year-over-year growth was driven by the Permian Basin, where the Company’s production increased by approximately 265%, more than offsetting the impact of non-core divestitures over the period. Crude oil production during the third quarter of 2018 averaged 40,813 Bbls/d, an increase of 17% versus the third quarter of 2017; natural gas and NGL production were 74,072 Mcf/d and 11,469 Bbls/d, respectively, during the third quarter of 2018. Third quarter of 2018 production exceeded the high end of the Company’s guidance range of 62,000-63,000 Boe/d.

Drilling, completion, and infrastructure capital expenditures for the third quarter of 2018 were $241.1 million. Approximately 62% of the third quarter drilling, completion, and infrastructure spending was in the Eagle Ford Shale, with the balance in the Delaware Basin. Land and seismic capital expenditures during the quarter were $6.7 million, and were primarily focused in the Delaware Basin.

For 2018, Carrizo is maintaining its drilling, completion, and infrastructure capital expenditure guidance of $800-$825 million. The Company’s 2018 development plan continues to call for it to run an average of 6 rigs for the balance of the year between its assets in the Eagle Ford Shale and Delaware Basin. Completion activity is expected to decline in the fourth quarter as the Company’s 2018 development plan has included a frac holiday during the quarter. Based on this level of activity, Carrizo expects to drill 123-132 gross (112-121 net) operated wells and complete 110-115 gross (95-100 net) operated wells during the year.

Carrizo is increasing its 2018 production guidance range to 60,200-60,500 Boe/d from 58,700-60,100 Boe/d. Crude oil is expected to account for 64%-65% of the Company’s production for the year, while total liquids are expected to account for 81%-82%. This equates to annual production growth of approximately 12% using the midpoint of the range. For the fourth quarter of the year, Carrizo expects production to be 67,700-68,700 Boe/d; crude oil is expected to account for 63% of production, while total liquids are expected to account for 80%. During the fourth quarter, Carrizo’s production has been negatively impacted by delays resulting from the heavy rains in Texas as well as maintenance on the DCP natural gas gathering system; DCP is the Company’s largest third-party gas gatherer in the Eagle Ford Shale. Additionally, fourth quarter Eagle Ford Shale production has been negatively impacted by elevated downtime in parent wells that offset slickwater completions. Combined, these items are expected to impact the Company’s production by more than 1,000 Bbls/d during the quarter, with the impact weighted to the Eagle Ford Shale. A full summary of Carrizo’s guidance is provided in the attached tables.

S.P. “Chip” Johnson, IV, Carrizo’s President and CEO, commented on the results, “The third quarter was another strong operational and financial quarter for the Company as we delivered production 3% above the high end of our guidance range with operating expenses below the midpoint of our guidance ranges. We continued to see the benefit of our dual-basin strategy during the quarter, as our Eagle Ford Shale production received 104% of NYMEX pricing. This shielded us from the significant widening of Permian Basin differentials and allowed us to expand our EBITDA margin to $35/Boe.

“During the third quarter, we completed our activity pivot to the Eagle Ford Shale. We currently have four of our six rigs operating in the play, where our production continues to benefit from advantaged pricing. We expect our activity to remain weighted to the Eagle Ford Shale until the second half of 2019, when we plan to begin moving rigs back to the Delaware Basin. We are using the increased activity in the Eagle Ford Shale to drill two additional large-scale multipad projects, which should help drive significant production growth when they come online in 2019.

“While the Eagle Ford Shale should be the primary driver of our production growth next year, we remain active in the Delaware Basin. During the quarter, we delivered strong well results from both our Phantom and Ford West areas and announced an attractive bolt-on acquisition in the Phantom area. Though the acquisition closed just last month, we have already begun to execute on some of the identified synergies. Over the next several quarters, we plan to focus our program in the basin on testing multi-layer development concepts throughout the Wolfcamp formation, which should help us maximize the long-term value of our asset.

“Our near- and long-term corporate goals include continuing to reduce our leverage and generating double-digit production growth within cash flow, and we continue to make progress toward achieving these targets. At the end of the third quarter, our leverage metric in accordance with our bank covenants fell below 2x, and we currently expect it to move even lower by year-end 2019. We also remain on track to achieving a free cash flow positive inflection point during 2019.”

Operational Update

In the Eagle Ford Shale, where the Company holds approximately 76,600 net acres, Carrizo drilled 32 gross (31 net) operated wells during the third quarter and completed 25 gross (24 net) operated wells. Production from the play was more than 39,000 Boe/d, up 5% versus the prior quarter. Crude oil production during the third quarter was nearly 30,000 Bbls/d, accounting for 77% of the Company’s production from the play. At the end of the quarter, Carrizo had 20 gross (19 net) operated Eagle Ford Shale wells waiting on completion. Carrizo currently expects to drill 95-100 gross (90-95 net) operated wells and complete 85-90 gross (75-80 net) operated wells in the play during 2018.

Performance from Carrizo’s initial multipad project, located in its Brown Trust area, continues to meet expectations. The Company now believes that multipad development combined with a lower-fluid, hybrid frac design, is the optimal development strategy where applicable. Advantages of multipad development include elimination of multiple parent-well frac hits, reduction in the total number of parent/child relationships created over time, and improvement in stimulation efficiency in the reservoir through the creation of enhanced multi-directional stress profiles during completion operations. At Brown Trust, the multipad project has resulted in very strong well results coupled with a material reduction in expected long-term, parent-well downtime in the area relative to a traditional 4-6 well pad approach. Carrizo has begun operations on two additional multipad projects, a 15-well project in its Pena Winfield area and a 23-well project in its RPG area. Production from both of these large-scale projects is expected in the first half of 2019.

In the Delaware Basin, where it holds more than 46,000 net acres, Carrizo drilled 7 gross (5 net) operated wells during the third quarter and completed 10 gross (9 net) operated wells. Production from the play was approximately 25,600 Boe/d for the quarter, up 29% versus the prior quarter. Crude oil production during the third quarter was approximately 10,900 Bbls/d, accounting for 42% of the Company’s production from the play. At the end of the quarter, Carrizo had 7 gross (6 net) operated Delaware Basin wells waiting on completion. Carrizo currently expects to drill 28-32 gross (22-26 net) operated wells and complete approximately 25 gross (20 net) operated wells in the play during 2018.

During the third quarter, Carrizo’s completion activity was spread across its Phantom and Ford West acreage, with strong results from both areas. Highlights from the Company’s third quarter activity include the following:

• the Davis 2728 Unit 10H achieved a peak 30-day rate of approximately 2,350 Boe/d (46% oil, 71% liquids) from an approximate 10,000-ft. lateral in the Wolfcamp A
• the Lovelace State Unit B912 11H has yet to achieve a peak 30-day rate, but recently averaged nearly 2,100 Boe/d (40% oil, 68% liquids) over seven days from an approximate 6,950-ft. lateral in the Wolfcamp B
• the Sandhu State 14 12H achieved a peak 30-day rate of more than 1,950 Boe/d (34% oil, 64% liquids) from an approximate 10,000-ft. lateral in the Wolfcamp A
• the Mustang State Unit 20H achieved a peak 30-day rate of more than 1,600 Boe/d (48% oil, 72% liquids) from an approximate 6,150-ft. lateral in the Wolfcamp A

While the Davis 10H and the Lovelace State 11H build upon the Company’s track record of strong well results from the Wolfcamp A and B in its primary Phantom block, the Sandhu State 12H was a delineation well located on the Company’s most westerly acreage in the Phantom area. Carrizo is very encouraged by the performance of this well as production has remained relatively flat, achieving a peak 60-day rate of more than 1,800 Boe/d (35% oil, 65% liquids).

The Mustang State 20H is a Wolfcamp A test located in the Company’s Ford West area. The well is located approximately 3,000 ft. from its previously-drilled Mustang State 1H well and incorporated technical and operational learnings from Carrizo’s early activity in the area. The Mustang State 20H continues to perform very well, having recently recorded a peak 60-day rate of more than 1,500 Boe/d (47% oil, 71% liquids).

During October, Carrizo closed the previously-announced bolt-on acquisition of Delaware Basin properties from Devon Energy Corp.. The acquisition added approximately 10,000 net acres adjacent to the Company’s Phantom position and approximately 1,700 Boe/d of net production. Since acquiring the asset, Carrizo has identified more than 1,000 additional net acres on the position through the evaluation of reprocessed 3D seismic that it believes can be developed. The Company is also actively working to realize the identified operational efficiencies. Carrizo expects to fully integrate the newly-acquired water disposal system into its existing system by year-end, which should allow it to shift the disposal of produced water from some of its wells from a third-party disposal site to Company-owned disposal wells acquired in the transaction. The Company has also identified a number of existing wells where it believes production can be increased by optimizing artificial lift, and expects to begin this activity shortly. Additionally, as a result of the acquisition, Carrizo will be able to drill an upcoming well in the southeast portion of its Phantom acreage in an optimized location, as it can now drill it as an allocation well using a reduced lease-line setback. This should lead to a more efficient development of its acreage in this area.

With the Eagle Ford set to be the primary driver of the Company’s production growth over the next year, Carrizo plans to focus much of its near-term Delaware Basin activity on testing additional layers as well as multi-layer cube concepts. This should allow the Company to formulate a development plan that maximizes the value of its vast resource potential in the basin. Some of the near-term multi-layer tests the Company has planned include a 6-well cube in the Phantom area testing co-development of the Wolfcamp A, B, and C and a 3-well cube in the Ford West area testing co-development of the Wolfcamp A and B. Carrizo’s current estimate of net de-risked drilling locations in the Delaware Basin includes only Wolfcamp A locations in the Ford West area and Wolfcamp A and B locations in the Phantom area. Carrizo currently plans to provide updates on these projects, as well as additional development tests, once it has sufficient production history.

Borrowing Base Update

During October, Carrizo’s banking syndicate, led by Wells Fargo as administrative agent, completed its semi-annual borrowing base redetermination. In conjunction with this, the borrowing base under the Company’s senior credit facility was increased to $1.3 billion from $1.0 billion, and Carrizo elected a commitment amount of $1.1 billion. Additionally, the interest rate on the Company’s facility has been reduced by 25 basis points to LIBOR plus 125-225 basis points. The next scheduled redetermination of the borrowing base is expected in the spring of 2019.

Hedging Activity

Carrizo currently has hedges in place for approximately 70% of estimated crude oil production for the remainder of 2018 (based on the midpoint of guidance). For 2019, the Company has three-way collars covering 27,000 Bbls/d. Additionally, Carrizo has hedges in place for approximately 45% and 30% of its estimated NGL and natural gas production, respectively, for the remainder of 2018.

In order to further manage its commodity price exposure, Carrizo has also put various basis hedges in place. For the balance of the year, Carrizo has basis swaps locking in a $0.10/Bbl Midland-Cushing differential on 6,000 Bbls/d. The Company also has basis swaps locking in a $5.11/Bbl LLS-Cushing premium on 18,000 Bbls/d over the same period.

Please refer to the attached tables for full details of the Company’s commodity derivative contracts.

Conference Call Details

The Company will hold a conference call to discuss 2018 third quarter financial results on Tuesday, November 6, 2018 at 10:00 AM Central Standard Time. To participate in the call, please dial (877) 256-6033 (U.S. & Canada) or +1 (303) 223-4376 (Intl.) ten minutes before the call is scheduled to begin. A replay of the call will be available through Tuesday, November 13, 2018 at 12:00 PM Central Standard Time at (800) 633-8284 (U.S. & Canada) or +1 (402) 977-9140 (Intl.). The reservation number for the replay is 21897149 for U.S., Canadian, and International callers.

A simultaneous webcast of the call may be accessed over the internet by visiting the Carrizo website at http://www.carrizo.com, clicking on “Upcoming Events”, and then clicking on the “Third Quarter 2018 Earnings Call” link. To listen, please go to the website in time to register and install any necessary software. The webcast will be archived for replay on the Carrizo website for 7 days.

Carrizo Oil & Gas, Inc. is a Houston-based energy company actively engaged in the exploration, development, and production of oil and gas from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

Statements in this release that are not historical facts, including but not limited to those related to capital requirements, effect of pivot to Eagle Ford, expectations or projections for the remainder of 2018 and 2019, generation and use of free cash flow, weighting of activity among basins, maximization of value, goals, leverage metrics, capital expenditure, infrastructure program, resource potential, guidance, rig program, production, average well returns, the estimated production results and financial performance, effects of transactions, targeted ratios and other metrics, timing, levels of and potential production, expectations regarding growth, oil and gas prices, drilling and completion activities, drilling inventory, including timing thereof, well costs, break-even prices, production mix, development plans, hedging activity, the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, results of the Company’s strategies and other statements that are not historical facts are forward-looking statements that are based on current expectations. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that these expectations will prove correct. Important factors that could cause actual results to differ materially from those in the forward-looking statements include assumptions regarding well costs, Delaware Basin constraints, estimated recoveries, pricing and other factors affecting average well returns, results of wells and testing, failure of actual production to meet expectations, results of infrastructure program, failure to reach significant growth, performance of rig operators, spacing test results, availability of gathering systems, pipeline and other transportation issues, costs and availability of oilfield services, actions by governmental authorities, joint venture partners, industry partners, lenders and other third parties, actions by purchasers or sellers of properties, risks and effects of acquisitions and dispositions, market and other conditions, risks regarding financing, capital needs, availability of well connects, capital needs and uses, commodity price changes, effects of the global economy on exploration activity, results of and dependence on exploratory drilling activities, operating risks, right-of-way and other land issues, availability of capital and equipment, weather, and other risks described in the Company’s Form 10-K for the year ended December 31, 2017 and its other filings with the U.S. Securities and Exchange Commission. There can be no assurance any transaction described in this press release will occur on the terms or timing described, or at all. The information regarding the Devon acquisition described in this press release assumes that the party to a joint operating agreement with the Company covering acreage in the vicinity of the acquired properties does not exercise its right to purchase 20% of the acreage covered by an area of mutual interest provision under that agreement.

(Financial Highlights to Follow)

Reconciliation of Net Income Attributable to Common Shareholders (GAAP) to Adjusted Net Income Attributable to Common Shareholders (Non-GAAP)

Adjusted net income attributable to common shareholders is a non-GAAP financial measure which excludes certain items that are included in net income attributable to common shareholders, the most directly comparable GAAP financial measure. Items excluded are those which the Company believes affect the comparability of operating results and are typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring.

Adjusted net income attributable to common shareholders is presented because management believes it provides useful additional information to investors for analysis of the Company’s fundamental business on a recurring basis. In addition, management believes that adjusted net income attributable to common shareholders is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Adjusted net income attributable to common shareholders should not be considered in isolation or as a substitute for net income attributable to common shareholders or any other measure of a company’s financial performance or profitability presented in accordance with GAAP. A reconciliation of the differences between net income attributable to common shareholders and adjusted net income attributable to common shareholders is presented below. Because adjusted net income attributable to common shareholders excludes some, but not all, items that affect net income attributable to common shareholders and may vary among companies, our calculation of adjusted net income attributable to common shareholders may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Income Attributable to Common Shareholders (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP)

Adjusted EBITDA is a non-GAAP financial measure which excludes certain items that are included in net income attributable to common shareholders, the most directly comparable GAAP financial measure. Items excluded are interest, income taxes, depreciation, depletion and amortization, impairments, dividends and accretion on preferred stock and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring.

Adjusted EBITDA is presented because management believes it provides useful additional information to investors and analysts, for analysis of the Company’s financial and operating performance on a recurring basis and the Company’s ability to internally generate funds for exploration and development, and to service debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Adjusted EBITDA should not be considered in isolation or as a substitute for net income attributable to common shareholders, net cash provided by operating activities, or any other measure of a company’s profitability or liquidity presented in accordance with GAAP. A reconciliation of net income attributable to common shareholders to adjusted EBITDA to net cash provided by operating activities is presented below. Because adjusted EBITDA excludes some, but not all, items that affect net income attributable to common shareholders, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flows (Non-GAAP)

Discretionary cash flows are a non-GAAP financial measure which excludes certain items that are included in net cash provided by operating activities, the most directly comparable GAAP financial measure. Items excluded are changes in the components of working capital and other items that the Company believes affect the comparability of operating cash flows such as items that are non-recurring.

Discretionary cash flows are presented because management believes it provides useful additional information to investors for analysis of the Company’s ability to generate cash to fund exploration and development, and to service debt. In addition, management believes that discretionary cash flows is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Discretionary cash flows should not be considered in isolation or as a substitute for net cash provided by operating activities or any other measure of a company’s cash flows or liquidity presented in accordance with GAAP. A reconciliation of net cash provided by operating activities to discretionary cash flows is presented below. Because discretionary cash flows excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of discretionary cash flows may not be comparable to similarly titled measures of other companies.