Exhibit 99.1

CARRIZO OIL & GAS, INC. ANNOUNCES THIRD QUARTER 2011 FINANCIAL RESULTS

HOUSTON, November 8, 2011—Carrizo Oil & Gas, Inc. (Nasdaq: CRZO) today announced the Company’s financial results for the third quarter of 2011, which included the following highlights:

Results for the third quarter of 2011—

Production volumes during the three months ended September 30, 2011 were 11.3 Bcfe, an increase of 2.7 Bcfe, or 31%, from third quarter 2010 production of 8.6 Bcfe and an increase of 0.1 Bcfe, or 1%, from second quarter 2011 production of 11.2 Bcfe. The increase in production from the third quarter of 2010 and the second quarter of 2011 to the third quarter of 2011 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties in May 2011.

Adjusted revenues were $58.7 million for the third quarter of 2011, which includes oil and gas revenues of $51.7 million and realized hedge gains of $7.0 million, compared to $38.9 million for the third quarter of 2010, which includes oil and gas revenues of $30.5 million and realized hedge gains of $8.4 million. The increase in adjusted revenues was primarily driven by increased production and higher oil prices partially offset by lower gas prices. Including the impact of realized hedges, the Company’s average realized gas price decreased 12% to $3.86 per Mcfe for the third quarter of 2011 compared to $4.37 per Mcfe for the third quarter of 2010 and the average realized oil price increased 25% to $91.38 per barrel for the third quarter of 2011 compared to $72.92 per barrel for the third quarter of 2010. Revenues excluding the impact of realized hedges are presented in the table below.

Adjusted net income, which excludes certain non-cash items described in the statements of operations included below (“Adjusted Net Income”), was $9.3 million, or $0.24 per basic and diluted share, during the third quarter of 2011, as compared to $21.0 million, or $0.61 and $0.60 per basic and diluted share, respectively, during the third quarter of 2010, including, for the third quarter of 2010, a $20.8 million benefit of cash distributions from a joint venture partner as described below. The Company reported net income of $21.6 million, or $0.56 and $0.55 per basic and diluted share, respectively, for the quarter ended September 30, 2011, as compared to net income of $12.8 million, or $0.37 per basic and diluted share, for the same quarter during 2010.

Earnings before interest, income tax, depreciation, depletion and amortization (“EBITDA”), as defined in the Company’s U.S. senior secured revolving credit facility (“Credit Facility”) and described in the statements of operations included below, was $41.6 million, or $1.07 and $1.06 per basic and diluted share, respectively, during the third quarter of 2011, as compared to $45.9 million, or $1.32 and $1.31 per basic and diluted share, respectively, during the third quarter of 2010. EBITDA for the third quarter of 2010 included the benefit of cash distributions totaling $20.8 million received from a joint venture partner as described below.

During the third quarter of 2010, the Company received cash distributions of $20.8 million on its B Unit investment in ACP II Marcellus, LLC (“ACP II”), a joint venture partner in the Marcellus Shale that is an affiliate of Avista Capital Partners, LP (“Avista”), a private equity fund, as a result of ACP II’s distribution to Avista of proceeds from its sale of oil and gas properties to an affiliate of Reliance Industries Limited (“Reliance”). Although such cash distributions are included in EBITDA and Adjusted Net Income, such cash distributions are recognized as a reduction of oil and gas property costs under the full cost method of accounting and accordingly, are not included in net income.

Lease operating expenses (including transportation costs of $1.8 million) were $7.3 million (or $0.65 per Mcfe) for the three months ended September 30, 2011 as compared to lease operating expenses (including transportation costs of $1.3 million) of $7.1 million (or $0.83 per Mcfe) for the third quarter of 2010. Lease operating expenses increased due to increased production partially offset by a decrease in workover costs, as the prior year included the workover of a high volume gas well in the Gulf Coast area. We continue to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively lower salt water disposal costs in our core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, including the non-core area Barnett Shale properties sold in May 2011. This decrease in operating cost per Mcfe was partially offset by increased operating cost per Mcfe associated with oil production in the Eagle Ford and Niobrara operating areas.

Production taxes were $1.3 million (or 2.6% of revenues) for the three months ended September 30, 2011 as compared to $0.7 million (or 2.3% of revenues) for the three months ended September 30, 2010. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.3% to 2.6% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.

Ad valorem taxes increased to $1.0 million (or $0.09 per Mcfe) for the three months ended September 30, 2011 from $0.7 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010.

General and administrative expense was $7.4 million during the three months ended September 30, 2011 as compared to $5.2 million during the three months ended September 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in the third quarter of 2011 as compared to the third quarter of 2010.

Depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2011 increased to $20.3 million (or $1.81 per Mcfe) from $10.1 million (or $1.18 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the third quarter of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford that were added after the third quarter of 2010 and have a higher future development cost per equivalent unit than the Company’s proved gas reserves.

Cash interest expense, net of amounts capitalized, increased to $6.5 million for the third quarter of 2011 compared to $2.9 million for the third quarter of 2010. The increase was primarily attributable to interest on the $400 million aggregate principal amount of our Senior Notes issued in the fourth quarter of 2010 partially offset by decreased interest attributable to the $300 million aggregate principal amount of Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

An unrealized gain on derivatives of $18.4 million was recorded for the third quarter of 2011 compared to an unrealized gain on derivatives of $12.9 million for the third quarter of 2010 due to the change in fair value of our open derivative positions during those periods.

Non-cash, stock-based compensation was a benefit of $4.1 million for the three months ended September 30, 2011 as compared to an expense of $4.4 million for the same period in 2010. The benefit from stock-based compensation expense was driven by a decrease in the fair value of cash-settled stock appreciation rights due to a decrease in stock price during the third quarter of 2011, partially offset by higher stock-based compensation expense due to a higher number of restricted stock awards granted during the period.

Non-cash interest expense, net of amounts capitalized, decreased to $0.8 million for the third quarter of 2011 compared to $1.9 million for the third quarter of 2010, primarily due to decreased amortization of the discount as a result of the $300 million aggregate principal amount of our Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the third quarter of 2011, we contributed $1.1 million in common stock to the Child Development Center at the University of Texas at Arlington (“UTA”), where we are producing natural gas from a number of wells in the Barnett Shale play.

The estimated annual effective income tax rates (which are used for purposes of computing Adjusted Net Income) as of September 30, 2011 and 2010 were 36.4% and 35.9%, respectively. The increase in the tax rate is due primarily to higher state income taxes associated with increased activity in Pennsylvania and Colorado. We expect substantially all of our income taxes to be deferred. The effective income tax rates for net income were 38.6% and 31.1% for the three months ended September 30, 2011 and 2010, respectively. The differences between these rates and our estimated annual effective income tax rates are due to true ups of prior estimates of state income taxes in both periods.

Results for the nine months ended September 30, 2011—

Production volumes during the nine months ended September 30, 2011 were a record 33.1 Bcfe, an increase of 7.0 Bcfe, or 27%, compared to production of 26.2 Bcfe during the nine months ended September 30, 2010. The increase in production for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties in May 2011.

Adjusted revenues were $165.7 million for the nine months ended September 30, 2011, which includes oil and gas revenues of $146.4 million and realized hedge gains of $19.3 million, compared to $126.3 million for the same period in 2010, which includes oil and gas revenues of $102.4 million and realized hedge gains of $23.9 million. The increase in adjusted revenues was primarily driven by increased production and higher oil prices partially offset by lower gas prices and lower realized hedge gains. Including the impact of realized hedges, the Company’s average realized gas price decreased 15% to $3.94 per Mcfe for the first nine months of 2011 compared to $4.62 per Mcfe for the first nine months of 2010 and the average realized oil price increased 13% to $91.74 per barrel for the first nine months of 2011 compared to $81.19 per barrel for the first nine months of 2010. Results excluding the impact of realized hedges are presented in the table below.

Adjusted Net Income was $29.6 million, or $0.76 and $0.75 per basic and diluted share, respectively, during the nine months ended September 30, 2011, as compared to $44.6 million, or $1.34 and $1.32 per basic and diluted share, respectively, during the nine months ended September 30, 2010, including, the $3.3 million and $20.8 million benefit of cash distributions from a joint venture partner for the 2011 and 2010 periods, respectively, as described below. The Company reported net income of $30.1 million, or $0.77 and $0.76 per basic and diluted share, respectively for the nine months ended September 30, 2011, as compared to net income of $34.4 million, or $1.03 and $1.02 per basic and diluted share, respectively for the same period in 2010.

EBITDA, as defined, was $123.0 million, or $3.16 and $3.12 per basic and diluted share, respectively, during the nine months ended September 30, 2011, as compared to $109.8 million, or $3.30 and $3.26 per basic and diluted share, respectively, for the same period in 2010. EBITDA for the nine months ended September 30, 2011 and 2010 included the benefit of cash distributions totaling $3.3 million and $20.8 million, respectively, received from a joint venture partner as described below.

During the second quarter of 2011 and the third quarter of 2010, the Company received cash distributions of $3.3 million and $20.8 million, respectively, on its B Unit investment in ACP II as a result of ACP II’s distribution to Avista of proceeds from its sale of oil and gas properties to Reliance. Although such cash distributions are included in EBITDA and Adjusted Net Income, such cash distributions are recognized as a reduction of oil and gas property costs under the full cost method of accounting and accordingly, are not included in net income.

Lease operating expenses (including transportation costs of $4.7 million) were $21.4 million (or $0.64 per Mcfe) for the nine months ended September 30, 2011 as compared to lease operating expenses (including transportation costs of $4.1 million) of $18.4 million (or $0.70 per Mcfe) for the nine months ended September 30, 2010. Lease operating expenses increased due to increased production. We continue to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively lower salt water disposal costs in our core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, including the non-core area Barnett Shale properties sold in May 2011. This decrease in operating cost per Mcfe was partially offset by increased operating cost per Mcfe associated with oil production in the Eagle Ford and Niobrara operating areas.

Production taxes increased to $3.7 million (or 2.6% of revenues) for the nine months ended September 30, 2011 from $2.5 million (or 2.4% of revenues) for the same period in 2010.The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.4% to 2.6% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.

Ad valorem taxes increased to $2.7 million ($0.08 per Mcfe) for the nine months ended September 30, 2011 from $2.4 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010.

General and administrative expenses were $18.1 million for the nine months ended September 30, 2011 as compared to $14.0 million for the nine months ended September 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in 2011 as compared to 2010.

DD&A expense for the nine months ended September 30, 2011 increased to $57.6 million (or $1.74 per Mcfe) from $31.0 million (or $1.19 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the first nine months of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford that were added subsequent to the third quarter of 2010, and have a higher future development cost per equivalent unit than the Company’s proved gas reserves.

Cash interest expense, net of amounts capitalized, was $18.7 million for the nine months ended September 30, 2011 compared to $9.1 million for the same period 2010. The increase was primarily attributable to interest on the $400 million aggregate principal amount of the Senior Notes issued in the fourth quarter of 2010 partially offset by decreased interest attributable to the $300 million aggregate principal amount of our Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

An unrealized gain on derivatives of $17.1 million was recorded for the nine months ended September 30, 2011 compared to an unrealized gain on derivatives of $23.1 million for the same period in 2010 due to the changes in fair value of our open derivative positions during those periods.

Non-cash, stock-based compensation expense was $6.6 million for the nine months ended September 30, 2011 compared to $9.7 million for the same period in 2010. The decrease in stock-based compensation expense was driven by a decrease in the fair value of cash-settled stock appreciation rights due to a decrease in stock price during the third quarter of 2011, partially offset by higher stock-based compensation expense due to a higher number of restricted stock awards granted during 2011.

Non-cash interest expense, net of amounts capitalized, decreased to $2.4 million for the nine months ended September 30, 2011 from $5.9 million for the same period 2010, primarily due to decreased amortization of the discount as a result of the $300 million aggregate principal amount of our Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the nine months ended September 30, 2011, we contributed $2.1 million in common stock to UTA, where we are producing natural gas from a number of wells in the Barnett Shale play.

In January 2011, in connection with our entrance into the Credit Facility, we terminated our prior credit facility. As a result, we recognized a non-cash, pre-tax loss on extinguishment of debt of $0.9 million representing the deferred financing costs attributable to the commitments of two banks in the prior credit facility who did not participate in the Credit Facility.

The estimated annual effective income tax rates (which are used for purposes of computing Adjusted Net Income) as of September 30, 2011 and 2010 were 36.4% and 35.9%, respectively. The increase in the tax rate is due primarily to higher state income taxes associated with increased activity in Pennsylvania and Colorado. We expect substantially all of our income taxes to be deferred. The effective income tax rates for net income were 37.7% and 35.4% for the nine months ended September 30, 2011 and 2010, respectively. The differences between these rates and our estimated annual effective income tax rates are due to true ups of prior estimates of state income taxes in both periods.

Carrizo’s President and CEO, S. P. “Chip” Johnson, IV, commented, “Production performance from new and recently completed wells in all our areas of operation continues to meet or exceed our expectations, as we brought on five gross Eagle Ford Shale, two Niobrara Formation and eight Barnett Shale wells in the third quarter. The largest contributor to our production short-fall came from lower than forecasted production from our non-operated Barnett Shale properties and a steeper than anticipated decline in our approximately 10 Mmcfe per day of Gulf Coast production. Delays in the completion of gas gathering systems in the Eagle Ford and Marcellus Shales also negatively impacted our gas production. Our oil production was within the range of our expectations despite delayed Eagle Ford Shale completions caused by a service company’s equipment problems.

“Our expectation for the fourth quarter calls for a large increase in Eagle Ford Shale production as 13 gross new wells are scheduled to come on production. Our first operated Marcellus production began from two gross wells in mid-October and gas production should benefit from the addition of three gross wells in December, all from Susquehanna County. Niobrara production should increase with the addition of two gross new wells that came on production the last day of the third quarter and one additional gross well that should come on production in December. The combined effect of these new wells, offset by the volumes associated with the interest in the Eagle Ford Shale properties transferred to GAIL (INDIA) LIMITED in our recently announced joint venture, leads to our guidance for production in the quarter to range between 137 and 143 Mmcfe per day. We continue to believe that we will achieve our previous goal of 5,000 net barrels per day of oil production before the end of the quarter.”

The Company will host a conference call to discuss 2011 third quarter financial results on Tuesday, November 8, 2011 at 10:00 AM Central Standard Time. To participate in the call, please dial (800) 683-0779 ten minutes before the call is scheduled to begin. A replay of the call will be available through Friday, November 19, 2011 at 11:59 AM Central Standard Time at (800) 633-8284. The conference ID for the replay is 21542966.

A simultaneous webcast of the call may be accessed over the internet at http://www.investorcalendar.com/IC/CEPage.asp?ID=165192 or by visiting our website at http://www.crzo.net, clicking on “Investor Relations” and then clicking on “2011 Third Quarter Conference Call Webcast.” To listen, please go to either website in time to register and install any necessary software. The webcast will be archived for replay on the Carrizo website for 15 days.

Carrizo Oil & Gas, Inc. is a Houston-based energy company actively engaged in the exploration, development, exploitation, and production of oil and gas primarily in the Eagle Ford Shale in South Texas, the Barnett Shale in North Texas, the Marcellus Shale in Appalachia, the Niobrara Formation in Colorado, the Utica Shale in Ohio and in proven onshore trends along the Texas and Louisiana Gulf Coast regions. Carrizo is also actively developing its oil discovery known as the Huntington Field in the UK North Sea. Carrizo controls significant prospective acreage blocks and utilizes advanced drilling and completion technology along with sophisticated 3-D seismic techniques to identify potential oil and gas drilling opportunities and to optimize reserve recovery.

Statements in this news release that are not historical facts, including but not limited to those related to timing and levels of production, drilling and completion, production mix, development plans, growth, use of proceeds, oil and gas sales, 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, timing of completion and drilling of wells, completion and pipeline connections, expected income tax rates and deferral of income taxes and other statements that are not historical facts are forward-looking statements that are based on current expectations. Although Carrizo 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 results of wells and production testing, performance of rig operators and gathering systems, actions by governmental authorities, joint venture partners, industry partners, lenders and other third parties, market and other conditions, 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 Carrizo’s Form 10-K for the year ended December 31, 2010 and its other filings with the Securities and Exchange Commission.

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CARRIZO OIL & GAS, INC.

STATEMENTS OF OPERATIONS

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CARRIZO OIL & GAS, INC.

CONDENSED BALANCE SHEETS

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CARRIZO OIL & GAS, INC.

PRODUCTION VOLUMES AND PRICES

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