Exhibit 99.1
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| CARRIZO OIL & GAS, INC. | | News |
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| PRESS RELEASE | | Contact: | | Carrizo Oil & Gas, Inc. |
| | | | Richard Hunter, Vice President of Investor Relations |
| | | | Paul F. Boling, Chief Financial Officer |
| | | | (713) 328-1000 |
CARRIZO OIL & GAS, INC. ANNOUNCES FOURTH QUARTER AND FULL YEAR 2011 FINANCIAL RESULTS
HOUSTON, February 28, 2012 - Carrizo Oil & Gas, Inc. (Nasdaq: CRZO)today announced the Company’s financial results for the fourth quarter of 2011, which included the following highlights:
Results for the fourth quarter of 2011—
| • | | Record production of 11.9 Bcfe, or 129,793 Mcfe/d, an increase of 12% from the fourth quarter of 2010 |
| • | | Revenue of $55.8 million, or adjusted revenue of $66.3 million, including the impact of realized hedges |
| • | | Oil revenue of $28.2 million, or 51% of total revenue |
| • | | Net Income of $6.5 million, or Adjusted Net Income (as defined below) of $9.1 million, essentially flat compared to the third quarter of 2011 due largely to higher DD&A (of $6.7 million) due to the predominant increase in proved oil reserves which has a higher finding cost per energy equivalent than natural gas |
| • | | EBITDA, as defined below, of $48.9 million |
Production volumes during the three months ended December 31, 2011 were 11.9 Bcfe, an increase of 1.2 Bcfe, or 12%, from fourth quarter 2010 production of 10.7 Bcfe and an increase of 0.6 Bcfe, or 6%, from third quarter 2011 production of 11.3 Bcfe. The increase in production from the fourth quarter of 2010 and the third quarter of 2011 to the fourth quarter of 2011 was primarily due to increased production from new wells, partially offset by normal production decline.
Adjusted revenues were $66.3 million for the fourth quarter of 2011, which includes oil and gas revenues of $55.8 million and realized hedge gains of $10.5 million, compared to $46.2 million for the fourth quarter of 2010, which includes oil and gas revenues of $35.8 million and realized hedge gains of $10.4 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 6% to $3.68 per Mcfe for the fourth quarter of 2011 compared to $3.93 per Mcfe for the fourth quarter of 2010 and the average realized oil price increased 20% to $100.43 per barrel for the fourth quarter of 2011 compared to $83.81 per barrel for the fourth 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 $9.1 million, or $0.23 per basic and diluted share, during the fourth quarter of 2011, as compared to $19.5 million, or $0.55 and $0.54 per basic and diluted share, respectively, during the fourth quarter of 2010, including an $18.0 million benefit of cash distributions from a joint venture partner for the fourth quarter of 2010, as described below. The Company reported net income of $6.5 million, or $0.17 and $0.16 per basic and diluted share, respectively, for the quarter ended December 31, 2011, as compared to a net loss of $24.4 million, or $0.69 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 $48.9 million, or $1.24 and $1.23 per basic and diluted share, respectively, during the fourth quarter of 2011, as compared to $52.2 million, or $1.47 and $1.45 per basic and diluted share, respectively, during the fourth quarter of 2010. EBITDA for the fourth quarter of 2010 included the benefit of cash distributions totaling $18.0 million received from a joint venture partner as described below.
During the fourth quarter of 2010, the Company received cash distributions of $18.0 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 $1.1 million) were $6.9 million (or $0.58 per Mcfe) for the three months ended December 31, 2011 as compared to lease operating expenses (including transportation costs of $0.9 million) of $5.3 million (or $0.50 per Mcfe) for the fourth quarter of 2010. Lease operating expenses increased due to increased production. The increase in operating cost per Mcfe is due to the higher operating cost per Mcfe associated with oil production as well as the true up of prior estimates that benefited the fourth quarter of 2010.
Production taxes were $2.0 million (or 3.5% of revenues) for the three months ended December 31, 2011 as compared to $1.2 million (or 3.3% of revenues) for the three months ended December 31, 2010. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 3.3% to 3.5% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.
Ad valorem taxes decreased to $0.9 million (or $0.08 per Mcfe) for the three months ended December 31, 2011 from $1.3 million ($0.12 per Mcfe) for the same period in 2010. The decrease in ad valorem taxes is due to the sale of substantially all of our non-core area Barnett Shale properties in May 2011, partially offset by new oil and gas wells drilled in 2010.
General and administrative expense was $7.6 million during the three months ended December 31, 2011 as compared to $4.3 million during the three months ended December 31, 2010. The increase was primarily due to increased compensation costs related to an increase in personnel in the fourth quarter of 2011 as compared to the fourth quarter of 2010 and increased office costs related to relocating the corporate headquarters in the fourth quarter of 2011.
Depreciation, depletion and amortization (“DD&A”) expense for the fourth quarter of 2011 increased $6.7 million to $27.0 million ($2.26 per Mcfe or $13.56 per BOE) from the DD&A expense for the third quarter of 2011 of $20.3 million ($1.81 per Mcfe or $10.86 per BOE) and from the DD&A expense for the fourth quarter of 2010 of $16.0 million ($1.50 per Mcfe or $9.00 per BOE). The increases in DD&A and the related per Mcfe amounts were primarily due to the increase in crude oil reserves in the Eagle Ford that were added in 2011, which have a higher finding cost per equivalent unit than the Company’s natural gas reserves.
Cash interest expense, net of amounts capitalized, increased to $7.4 million for the fourth quarter of 2011 compared to $5.7 million for the fourth 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 and the $200 million aggregate principal amount of our Senior Notes issued in the fourth quarter of 2011, partially offset by decreased interest attributable to the repurchase of $300 million aggregate principal amount of Convertible Senior Notes in a tender offer during the fourth quarter of 2010.
An unrealized loss on derivatives of $1.4 million was recorded for the fourth quarter of 2011 compared to an unrealized loss on derivatives of $10.2 million for the fourth quarter of 2010 due to the change in fair value of our open derivative positions during those periods.
Non-cash, stock-based compensation expense of $5.3 million was recorded for the three months ended December 31, 2011 as compared to $6.9 million for the same period in 2010. The decrease in stock-based compensation expense was driven by a smaller increase in the fair value of cash-settled stock appreciation rights due to a smaller increase in stock price during the fourth quarter of 2011 as compared to the fourth quarter of 2010, partially offset by higher stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during the period.
Non-cash interest expense, net of amounts capitalized, decreased to $1.0 million for the fourth quarter of 2011 compared to $1.8 million for the fourth quarter of 2010, primarily due to decreased amortization of the discount as a result of the repurchase of $300 million aggregate principal amount of our Convertible Senior Notes in a tender offer during the fourth quarter of 2010.
The estimated annual effective income tax rates (which are used for purposes of computing Adjusted Net Income) for the year ended December 31, 2011 and 2010 were 36.6% and 35.9%. Substantially all of the income tax expense for the three months ended December 31, 2011 was offset by the prior period adjustments related to the Company’s state and U.K. income tax provisions recorded during the fourth quarter of 2011. The actual effective income tax rate for the three months ended December 31, 2010 was 34.9%, which was lower than the estimated annual effective income tax rate for 2010 due to true ups of prior estimates of state income taxes.
Results for the year ended December 31, 2011—
| • | | Record production of 45.1 Bcfe, or 123,448 Mcfe/d |
| • | | Revenue of $202.2 million, or adjusted revenue of $231.9 million, including the impact of realized hedges |
| • | | Net Income of $36.6 million, or Adjusted Net Income of $38.8 million |
| • | | EBITDA of $172.1 million |
Production volumes during the year ended December 31, 2011 were a record 45.1 Bcfe, an increase of 8.3 Bcfe, or 22%, compared to production of 36.8 Bcfe during the year ended December 31, 2010. The increase in production for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily due to increased production from new wells, partially offset by normal production decline.
Adjusted revenues were $231.9 million for the year ended December 31, 2011, which includes oil and gas revenues of $202.2 million and realized hedge gains of $29.7 million, compared to $172.5 million for the year ended December 31, 2010, which includes oil and gas revenues of $138.1 million and realized hedge gains of $34.4 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 12% to $3.88 per Mcfe for 2011 compared to $4.42 per Mcfe for 2010 and the average realized oil price increased 15% to $94.69 per barrel for 2011 compared to $82.25 per barrel for 2010. Revenues excluding the impact of realized hedges are presented in the table below.
Adjusted Net Income was $38.8 million, or $0.99 and $0.98 per basic and diluted share, respectively, during the year ended December 31, 2011, as compared to $64.1 million, or $1.89 and $1.87 per basic and diluted share, respectively, during the year ended December 31, 2010, including a $3.3 million and $38.8 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 $36.6 million, or $0.94 and $0.92 per basic and diluted share, respectively, for the year ended December 31, 2011, as compared to net income of $9.9 million, or $0.29 per basic and diluted share for the year ended December 31, 2010.
EBITDA, as defined, was $172.1 million, or $4.40 and $4.34 per basic and diluted share, respectively, during the year ended December 31, 2011, as compared to $162.1 million, or $4.79 and $4.72 per basic and diluted share, respectively, for the year ended December 31, 2010. EBITDA for the years ended December 31, 2011 and 2010 included the benefit of cash distributions totaling $3.3 million and $38.8 million, respectively, received from a joint venture partner as described below.
During 2011 and 2010, the Company received cash distributions of $3.3 million and $38.8 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 $5.7 million) were $28.3 million (or $0.63 per Mcfe) for the year ended December 31, 2011 as compared to lease operating expenses (including transportation costs of $5.1 million) of $23.7 million (or $0.65 per Mcfe) for the year ended December 31, 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 which was partially offset by higher operating cost per Mcfe associated with oil production.
Production taxes increased to $5.7 million (or 2.8% of revenues) for the year ended December 31, 2011 from $3.6 million (or 2.6% of revenues) for the year ended December 31, 2010. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.6% to 2.8% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.
Ad valorem taxes decreased to $3.6 million ($0.08 per Mcfe) for the year ended December 31, 2011 from $3.7 million ($0.10 per Mcfe) for the year ended December 31, 2010. The decrease in ad valorem taxes is due to the sale of substantially all of our non-core area Barnett Shale properties in May 2011, partially offset by new oil and gas wells drilled in 2010.
General and administrative expenses were $25.6 million for the year ended December 31, 2011 as compared to $18.3 million for the year ended December 31, 2010. The increase was primarily due to increased compensation costs related to an increase in personnel in 2011 as compared to 2010 and increased office costs related to relocating the corporate headquarters in the fourth quarter of 2011.
DD&A expense for the year ended December 31, 2011 increased to $84.6 million ($1.88 per Mcfe or $11.28 per BOE) from $47.0 million ($1.28 per Mcfe or $7.68 per BOE) for the year ended December 31, 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to the increase in crude oil reserves in the Eagle Ford that were added in 2011 which have a higher finding cost per equivalent unit than the Company’s natural gas reserves.
Cash interest expense, net of amounts capitalized, was $26.1 million for the year ended December 31, 2011 compared to $14.8 million for the year ended December 31, 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 and the $200 million aggregate principal amount of the Senior Notes issued in the fourth quarter of 2011, partially offset by decreased interest attributable to the $300 million aggregate principal amount of our repurchase of Convertible Senior Notes in a tender offer during the fourth quarter of 2010.
An unrealized gain on derivatives of $15.7 million was recorded for the year ended December 31, 2011 compared to an unrealized gain on derivatives of $12.9 million for the year ended December 31, 2010 due to the changes in fair value of our open derivative positions during those periods.
Non-cash, stock-based compensation expense was $11.9 million for the year ended December 31, 2011 compared to $16.6 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 second half of 2011, partially offset by higher stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during 2011.
Non-cash interest expense, net of amounts capitalized, decreased to $3.4 million for the year ended December 31, 2011 from $7.7 million for the same period 2010, primarily due to decreased amortization of the discount as a result of the repurchase of $300 million aggregate principal amount of our Convertible Senior Notes in a tender offer during the fourth quarter of 2010.
During 2011, we contributed $2.1 million in common stock to the University of Texas at Arlington, a university located within the area of our operations in the Barnett Shale.
The estimated annual effective income tax rates (which are used for purposes of computing Adjusted Net Income) for the year ended December 31, 2011 and 2010 were 36.6% and 35.9%. The actual effective income tax rates for the years ended December 31, 2011 and 2010 were 33.2% and 36.5%, respectively. The differences between the actual effective income tax rates and our estimated annual effective income tax rates are due to true ups of prior estimates of state income taxes in both periods as well as prior period adjustments related to the Company’s state and U.K. income tax provisions recorded during the fourth quarter of 2011.
Carrizo’s President and CEO, S. P. “Chip” Johnson, IV, commented, “2011 was a transformational year as our rapid growth in oil production spurred a shift in our revenue balance from being historically dependent on natural gas, to reaching parity in our oil to gas revenue ratio in the fourth quarter. We expect this trend to continue for the entire year of 2012 as we become increasingly weighted toward oil production. Evidence in our success in oil focused drilling during the year is best seen in the increase in the value of our reserves. Our proved reserves’ PV-10 value grew 44% from $1.01 billion at year-end 2010 to $1.45 billion at year-end 2011, driven by an increase in the oil component from 30 % of the value in 2010 to 53% in 2011. Because of our higher anticipated oil to gas production mix for 2012, at flat $95 oil and $3.15 gas, our forecast 30% overall growth in domestic production would generate an approximate 80% increase in EBITDA due to the higher margins associated with oil. We chose to exclude the effect of the initiation of production from our interest in the North Sea Huntington development project from our 2012 production guidance issued earlier this month due to the large variance created by the exact timing of first oil. Comments from the project FPSO operator indicate first production is expected this October and should quickly reach the forecast rate of 4,500 Boepd net to Carrizo. Our staff did an outstanding job this year transforming the Company from being a gas producer to an oil producer.”
The Company will host a conference call to discuss 2011 fourth quarter and full year financial results on Tuesday, February 28, at 10:00 AM Central Standard Time. To participate in the call, please dial (800) 707-9231 ten minutes before the call is scheduled to begin. A replay of the call will be available through Tuesday, March 6, 2012 at 11:59 AM Central Standard Time at (800) 633-8284. The conference ID for the replay is 21579534.
A simultaneous webcast of the call may be accessed over the internet athttp://www.investorcalendar.com/IC/CEPage.asp?ID=167442 or by visiting our website athttp://www.crzo.net, clicking on “Investor Relations” and then clicking on “2011 Fourth 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, and production of oil and gas primarily in the United States and United Kingdom. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Niobrara Formation in Colorado, the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Utica Shale in Ohio and Pennsylvania, and the U.K. North Sea where our Huntington Field project is currently under development.
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.
(Financial Highlights to Follow)
CARRIZO OIL & GAS, INC.
STATEMENTS OF OPERATIONS
(unaudited)
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| | | THREE MONTHS ENDED
DECEMBER 31, | | | YEAR ENDED
DECEMBER 31, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Revenues: | | | | | | | | | | | | | | | | |
Oil and condensate | | $ | 28,218,562 | | | $ | 6,004,789 | | | $ | 75,502,306 | | | $ | 13,859,026 | |
Natural gas | | | 25,564,726 | | | | 26,872,774 | | | | 116,103,146 | | | | 113,597,846 | |
NGLs | | | 1,985,813 | | | | 2,866,056 | | | | 10,561,392 | | | | 10,666,644 | |
| | | | | | | | | | | | | | | | |
Total oil and gas revenues | | | 55,769,101 | | | | 35,743,619 | | | | 202,166,844 | | | | 138,123,516 | |
Realized gain on derivatives, net (1), (2) | | | 10,572,642 | | | | 10,426,765 | | | | 29,765,585 | | | | 34,358,771 | |
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Adjusted revenues | | | 66,341,743 | | | | 46,170,384 | | | | 231,932,429 | | | | 172,482,287 | |
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Costs and expenses: | | | | | | | | | | | | | | | | |
Lease operating | | | 6,928,889 | | | | 5,298,082 | | | | 28,314,145 | | | | 23,659,002 | |
Production taxes | | | 1,964,733 | | | | 1,166,211 | | | | 5,696,371 | | | | 3,648,097 | |
Ad valorem taxes | | | 926,801 | | | | 1,285,688 | | | | 3,624,819 | | | | 3,707,344 | |
General and administrative | | | 7,645,211 | | | | 4,308,988 | | | | 25,644,124 | | | | 18,303,143 | |
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Total costs and expenses | | | 17,465,634 | | | | 12,058,969 | | | | 63,279,459 | | | | 49,317,586 | |
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Other items of income (expense) included in EBITDA, as defined: | | | | | | | | | | | | | | | | |
Cash Distributions-Related Party (3) | | | — | | | | 18,046,445 | | | | 3,333,333 | | | | 38,839,093 | |
Other income, net | | | 1,013 | | | | 61,077 | | | | 79,663 | | | | 49,812 | |
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EBITDA, as defined | | $ | 48,877,123 | | | $ | 52,218,937 | | | $ | 172,065,966 | | | $ | 162,053,606 | |
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EBITDA per common share-Basic | | $ | 1.24 | | | $ | 1.47 | | | $ | 4.40 | | | $ | 4.79 | |
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EBITDA per common share-Diluted | | $ | 1.23 | | | $ | 1.45 | | | $ | 4.34 | | | $ | 4.72 | |
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Other items of income (expense) included in adjusted net income, as defined: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization expense (4) | | $ | (27,009,860 | ) | | $ | (16,015,219 | ) | | $ | (84,606,005 | ) | | $ | (47,029,994 | ) |
Cash interest expense | | | (13,055,520 | ) | | | (10,065,019 | ) | | | (46,733,281 | ) | | | (28,249,240 | ) |
Cash interest capitalized | | | 5,672,816 | | | | 4,332,480 | | | | 20,656,333 | | | | 13,447,830 | |
Accretion expense related to asset retirement obligations | | | (95,557 | ) | | | (56,724 | ) | | | (310,970 | ) | | | (216,242 | ) |
Interest income | | | 6,606 | | | | 1,288 | | | | 17,989 | | | | 3,268 | |
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Adjusted income before income taxes | | | 14,395,608 | | | | 30,415,743 | | | | 61,090,032 | | | | 100,009,228 | |
Adjusted income tax expense | | | (5,268,792 | ) | | | (10,925,335 | ) | | | (22,358,952 | ) | | | (35,923,315 | ) |
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ADJUSTED net income, as defined | | $ | 9,126,815 | | | $ | 19,490,408 | | | $ | 38,731,080 | | | $ | 64,085,913 | |
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ADJUSTED net income per common share-Basic | | $ | 0.23 | | | $ | 0.55 | | | $ | 0.99 | | | $ | 1.89 | |
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ADJUSTED net income per common share-Diluted | | $ | 0.23 | | | $ | 0.54 | | | $ | 0.98 | | | $ | 1.87 | |
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Other non-cash items of income (expense) included in net income: | | | | | | | | | | | | | | | | |
Unrealized gain (loss) on derivatives, net (2), (5) | | $ | (1,394,867 | ) | | $ | (10,203,125 | ) | | $ | 15,699,949 | | | $ | 12,914,061 | |
Stock-based compensation expense | | | (5,268,819 | ) | | | (6,892,517 | ) | | | (11,863,967 | ) | | | (16,608,421 | ) |
Non-cash interest expense | | | (1,746,637 | ) | | | (3,140,164 | ) | | | (6,070,023 | ) | | | (15,014,379 | ) |
Non-cash interest capitalized | | | 759,087 | | | | 1,351,682 | | | | 2,712,638 | | | | 7,298,080 | |
Non-cash reclassification of Cash Distributions-Related Party to oil and gas property costs (3) | | | — | | | | (18,046,445 | ) | | | (3,333,333 | ) | | | (38,839,093 | ) |
Non-cash contribution expense | | | — | | | | — | | | | (2,119,343 | ) | | | — | |
Non-cash rent expense | | | (448,547 | ) | | | — | | | | (598,063 | ) | | | — | |
Loss on extinguishment of debt | | | — | | | | (31,022,964 | ) | | | (896,850 | ) | | | (31,022,964 | ) |
Foreign currency gain (loss) | | | 270,305 | | | | (1,731 | ) | | | 258,735 | | | | (6,719 | ) |
Recovery of investment | | | — | | | | 165,339 | | | | — | | | | 165,339 | |
Impairment of oil and gas properties | | | — | | | | — | | | | — | | | | (2,730,882 | ) |
Allowance for doubtful accounts | | | (88,599 | ) | | | (117,437 | ) | | | (30,979 | ) | | | (485,338 | ) |
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Income (loss) before income taxes | | | 6,477,531 | | | | (37,491,619 | ) | | | 54,848,796 | | | | 15,678,912 | |
Income tax benefit (expense) | | | 32,564 | | | | 13,086,843 | | | | (18,219,853 | ) | | | (5,728,992 | ) |
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Net income (loss) | | $ | 6,510,095 | | | $ | (24,404,776 | ) | | $ | 36,628,943 | | | $ | 9,949,920 | |
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Net income (loss) per common share-Basic | | $ | 0.17 | | | $ | (0.69 | ) | | $ | 0.94 | | | $ | 0.29 | |
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Net income (loss) per common share-Diluted | | $ | 0.16 | | | $ | (0.69 | ) | | $ | 0.92 | | | $ | 0.29 | |
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Weighted average common shares outstanding-Basic | | | 39,361,232 | | | | 35,522,452 | | | | 39,076,871 | | | | 33,860,667 | |
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Weighted average common shares outstanding-Diluted | | | 39,766,681 | | | | 36,043,263 | | | | 39,667,859 | | | | 34,305,359 | |
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NOTES:
| (1) | Includes reclassifications of approximately $0.1 million and $0.0 million for the three months ended December 31, 2011 and 2010, respectively, and $0.7 million and $0.5 million for the years ended December, 2011 and 2010, respectively, from general and administrative to realized gain on derivatives, net, related to agency fees paid to enter into certain derivative positions. |
| (2) | Includes reclassifications of approximately $1.3 million and ($0.1) million for the three months ended December 31, 2011 and 2010, respectively and $5.0 million and ($1.6) million for the years ended December 31, 2011 and 2010, respectively, from unrealized gain on derivatives, net, to realized gain on derivatives, net, for cash received from the optimization of certain hedge positions that settle in future periods. Amounts for cash received are offset by the related non-cash amortization during the period in which such hedge positions settle. |
| (3) | During the fourth quarter of 2010 the Company received cash distributions of $18.0 million and for the years ended December 31, 2011 and 2010, the Company received cash distributions of $3.3 million and $38.8 million, respectively, on its B Unit investment in ACP II, a joint venture partner in the Marcellus Shale as a result of ACP II’s distribution to Avista of proceeds from the sale of oil and gas properties to Reliance in September 2010. These cash distributions are included in Adjusted Net Income and EBITDA, as defined in the Company’s U.S. revolving credit facility but excluded from Net Income, under the full cost method of accounting, as such distributions are recognized as a reduction of oil and gas property costs. |
| (4) | Results for the three months and year ended December 31, 2010, include reductions of $0.5 million and $0.8 million, respectively, to the DD&A previously presented in the preliminary fourth quarter and annual 2010 financial results. These preliminary results were reported before the potential effect of cash distributions discussed in Note (3) above. Because these distributions were subsequently recognized as a reductions of oil and gas property costs, DD&A was reduced accordingly. |
| (5) | Includes reclassifications of approximately $0.2 million and $0.0 million for the three months ended December 31, 2011 and 2010, respectively, and $0.8 million and $0.0 million for the years ended December 31, 2011 and 2010, respectively, from general and administrative to unrealized gain on derivatives, net, related to accrued agency fees incurred to enter into certain derivative positions. |
CARRIZO OIL & GAS, INC.
CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
| | | | | | | | |
| | | December 31, 2011 | | | December 31, 2010 | |
| | |
ASSETS: | | | | | | | | |
Cash and cash equivalents | | $ | 28,112 | | | $ | 4,128 | |
Fair value of derivative instruments | | | 27,877 | | | | 17,698 | |
Other current assets | | | 64,408 | | | | 38,506 | |
Deferred income taxes | | | 59,755 | | | | 72,587 | |
Property and equipment, net | | | 1,310,514 | | | | 983,057 | |
Other assets | | | 34,491 | | | | 24,766 | |
Investments | | | 2,523 | | | | 3,392 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 1,527,680 | | | $ | 1,144,134 | |
| | | | | | | | |
| | |
LIABILITIES AND SHAREHOLDERS’ EQUITY: | | | | | | | | |
Accounts payable and accrued liabilities | | $ | 261,151 | | | $ | 109,651 | |
Current maturities of long-term debt | | | — | | | | 160 | |
Other current liabilities | | | 10,169 | | | | 9,193 | |
Long-term debt, net of current maturities and debt discount | | | 729,300 | | | | 558,094 | |
Other liabilities | | | 17,196 | | | | 9,685 | |
Fair value of derivative instruments | | | 9 | | | | 715 | |
Shareholders’ equity | | | 509,855 | | | | 456,636 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 1,527,680 | | | $ | 1,144,134 | |
| | | | | | | | |
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CARRIZO OIL & GAS, INC.
PRODUCTION VOLUMES AND PRICES
(unaudited)
| | | | | | | | | | | | | | | | |
| | | THREE MONTHS ENDED
DECEMBER 31, | | | YEAR ENDED
DECEMBER 31, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | |
Production volumes- | | | | | | | | | | | | | | | | |
| | | | |
Oil and condensate (Bbls) | | | 286,527 | | | | 71,649 | | | | 801,846 | | | | 176,237 | |
Natural gas (Mcfe) | | | 10,013,315 | | | | 9,785,538 | | | | 38,990,596 | | | | 34,097,738 | |
NGLs (Mcfe) | | | 208,505 | | | | 440,962 | | | | 1,256,977 | | | | 1,659,210 | |
Natural gas and NGLs (Mcfe) | | | 10,221,820 | | | | 10,226,500 | | | | 40,247,573 | | | | 35,756,948 | |
Natural gas equivalent (Mcfe) | | | 11,940,984 | | | | 10,656,392 | | | | 45,058,649 | | | | 36,808,369 | |
| | | | |
Average sales prices- | | | | | | | | | | | | | | | | |
| | | | |
Oil and condensate ($ per Bbl) | | $ | 98.48 | | | $ | 83.81 | | | $ | 94.16 | | | $ | 78.64 | |
Oil and condensate ($ per Bbl) - with hedge impact | | $ | 100.43 | | | $ | 83.81 | | | $ | 94.69 | | | $ | 82.25 | |
Natural gas ($ per Mcfe) | | $ | 2.55 | | | $ | 2.75 | | | $ | 2.98 | | | $ | 3.33 | |
NGLs ($ per Mcfe) | | $ | 9.52 | | | $ | 6.50 | | | $ | 8.40 | | | $ | 6.43 | |
Natural gas and NGLs ($ per Mcfe) | | $ | 2.70 | | | $ | 2.91 | | | $ | 3.15 | | | $ | 3.48 | |
Natural gas and NGLs ($ per Mcfe) - with hedge impact | | $ | 3.68 | | | $ | 3.93 | | | $ | 3.88 | | | $ | 4.42 | |
Natural gas equivalent ($ per Mcfe) | | $ | 4.67 | | | $ | 3.35 | | | $ | 4.49 | | | $ | 3.75 | |
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