SOURCE: Carrizo Oil & Gas, Inc.

Carrizo Oil & Gas, Inc.

August 09, 2011 06:30 ET

Carrizo Oil & Gas, Inc. Announces Second Quarter 2011 Financial Results and Record Production

HOUSTON, TX--(Marketwire - Aug 9, 2011) - Carrizo Oil & Gas, Inc. (NASDAQ: CRZO) today announced the Company's financial results for the second quarter of 2011, which included the following highlights:

Results for the Second Quarter of 2011 --

  • Record production of 11.2 Bcfe, or 122,788 Mcfe/d

  • Revenue of $50.7 million or adjusted revenue, of $54.1 million, including the impact of realized hedges

  • Net Income of $7.7 million, or Adjusted Net Income, as defined below, of $9.5 million

  • EBITDA, as defined below, of $41.8 million

Production volumes during the three months ended June 30, 2011 were a record 11.2 Bcfe, an increase of 1.9 Bcfe, or 20%, from second quarter 2010 production of 9.3 Bcfe and an increase of 0.5 Bcfe, or 5% from first quarter 2011 production of 10.7 Bcfe. The increase in production from the second quarter of 2010 and the first quarter 2011 to the second 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 to KKR Natural Resources ("KKR") in May 2011.

Adjusted revenues were $54.1 million for the second quarter of 2011, which includes oil and gas revenues of $50.7 million and realized hedge gains of $3.4 million, compared to $43.5 million for the second quarter of 2010, which includes oil and gas revenues of $32.9 million and realized hedge gains of $10.6 million. The increase in adjusted revenues was primarily driven by increased production, particularly higher oil and condensate production in the Eagle Ford Shale, and higher oil prices partially offset by lower realized hedge gains. Including the impact of realized hedges, the Company's average realized gas price decreased 13% to $3.83 per Mcfe for the second quarter of 2011 compared to $4.40 per Mcfe for the second quarter of 2010 and the average realized oil price increased 1% to $93.90 per barrel for the second quarter of 2011 compared to $93.30 per barrel for the second 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 $9.5 million, or $0.25 and $0.24 per basic and diluted share, respectively, during the second quarter of 2011, including a $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $11.3 million, or $0.33 per basic and diluted share, during the second quarter of 2010. The Company reported net income of $7.7 million, or $0.20 per basic and diluted share, for the quarter ended June 30, 2011, as compared to net income of $1.8 million, or $0.05 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 new U.S. senior secured revolving credit facility ("Credit Facility") and described in the statements of operations included below was $41.8 million, or $1.07 and $1.06 per basic and diluted share, respectively, during the second quarter of 2011, including the $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $31.6 million, or $0.93 and $0.92 per basic and diluted share, respectively, during the second quarter of 2010. During the second quarter of 2011, the Company received cash distributions of $3.3 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, a private equity fund, as a result of ACP II's distribution to Avista of remaining 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 $1.6 million) were $7.4 million (or $0.66 per Mcfe) for the three months ended June 30, 2011 as compared to lease operating expenses (including transportation costs of $1.5 million) of $6.2 million (or $0.66 per Mcfe) for the second quarter of 2010. Lease operating expenses increased due to increased production primarily attributable to new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation. Although we continued to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively less salt water disposal costs in the core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, this decrease was offset by increased operating cost per Mcfe associated with higher cost oil production.

Production taxes were $1.5 million (or 2.89% of revenues) for the three months ended June 30, 2011 as compared to $0.9 million (or 2.69% of revenues) for the three months ended June 30, 2010. The increases in production taxes and the percentage of revenues are due to increased oil production, which has a higher effective production tax rate as compared to natural gas.

Ad valorem taxes increased to $1.0 million (or $0.05 per Mcfe) for the three months ended June 30, 2011 from $0.5 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 as well as a reduction in ad valorem taxes recorded in the second quarter of 2010 reflecting a true up of our first quarter 2010 estimate. The decrease in the per Mcfe amounts is due primarily to this true up of the first quarter 2010 estimate.

General and administrative expense was $5.7 million during the three months ended June 30, 2011 as compared to $4.3 million during the three months ended June 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in the second quarter of 2011.

Depreciation, depletion and amortization ("DD&A") expense for the three months ended June 30, 2011 increased to $20.6 million (or $1.84 per Mcfe) from $11.1 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 second 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 which were added during the fourth quarter of 2010 and have a higher future development cost per equivalent unit than the Company's proved gas reserves. The increase in the second quarter 2011 forecasted DD&A of $1.58 per Mcfe to the actual DD&A of $1.84 per Mcfe is largely due to increased production in the second quarter of 2011 as compared to the first quarter of 2011 as well as an increase in prior year's estimated future development costs in the Eagle Ford.

Cash interest expense, net of amounts capitalized, increased to $6.1 million for the second quarter of 2011 compared to $2.9 million for the second quarter of 2010. The increase was primarily attributable to interest on the $400 million aggregate principal amount of 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 $8.1 million was recorded for the second quarter of 2011 compared to an unrealized loss on derivatives of $7.4 million for the second quarter of 2010 due to the change in fair value of our open derivative positions during those periods.

Non-cash, stock-based compensation expense increased to $6.8 million for the three months ended June 30, 2011 from $3.2 million for the same period in 2010. The increase was largely attributable to additional stock appreciation rights as well as stock appreciation rights that increased in fair value.

Non-cash interest expense, net of amounts capitalized, decreased to $0.7 million for the second quarter of 2011 compared to $1.9 million for the second quarter of 2010, primarily due to decreased amortization of the discount as a result of the $300 million aggregate principal amount of the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the second quarter of 2011, we contributed $1.0 million in common stock to the Carrizo Oil & Gas, Inc. endowed scholarship fund 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 effective income tax rate was 31.8% for the second quarter of 2011 and 15.0% for the second quarter of 2010. Our estimated annual effective income tax rate for 2011 is approximately 37%, substantially all of which we expect to be deferred. The effective income tax rate for the second quarter of 2011 was lower than 37% primarily due to the true up of prior estimates of the foreign tax benefit associated with the Company's UK Huntington field development. The lower rate in the second quarter of 2010 was due to a true up of prior estimates of state income tax.

Results for the Six Months Ended June 30, 2011--

  • Record production of 21.9 Bcfe, or 120,805 Mcfe/d

  • Revenue of $94.7 million, or adjusted revenue of $106.9 million, including the impact of realized hedges

  • Net Income of $8.5 million, or Adjusted Net Income of $20.2 million

  • EBITDA of $81.4 million

Production volumes during the six months ended June 30, 2011 were a record 21.9 Bcfe, an increase of 4.3 Bcfe, or 25%, compared to production of 17.6 Bcfe during the six months ended June 30, 2010. The increase in production for the six months ended June 30, 2011 as compared to the six months ended June 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 to KKR in May 2011.

Adjusted revenues were $106.9 million for the six months ended June 30, 2011, which includes oil and gas revenues of $94.7 million and realized hedge gains of $12.2 million, compared to $87.3 million for the same period in 2010, which includes oil and gas revenues of $71.9 million and realized hedge gains of $15.4 million. The increase in adjusted revenues was primarily driven by increased production, particularly higher oil and condensate production in the Eagle Ford Shale, 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 16% to $3.99 per Mcfe for the first six months of 2011 compared to $4.73 per Mcfe for the first six months of 2010 and the average realized oil price increased 8% to $91.59 per barrel for the first six months of 2011, compared to $84.75 per barrel for the first six months of 2010. Results excluding the impact of realized hedges are presented in the table below.

Adjusted Net Income was $20.2 million, or $0.52 and $0.51 per basic and diluted share, respectively, during the six months ended June 30, 2011, including a $3.3 million benefit of cash distributions received from a joint venture partner as described above, as compared to $23.7 million, or $0.73 and $0.72 per basic and diluted share, respectively, during the six months ended June 30, 2011. The Company reported net income of $8.5 million, or $0.22 and $0.21 per basic and diluted share, respectively for the six months ended June 30, 2011, as compared to net income of $21.5 million, or $0.66 and $0.65 per basic and diluted share, respectively for the same period in 2010.

EBITDA was $81.4 million, or $2.10 and $2.06 per basic and diluted share, respectively, during the six months ended June 30, 2011, including the $3.3 million benefit of cash distributions received from a joint venture partner as described above, as compared to $63.9 million, or $1.96 and $1.94 per basic and diluted share, respectively, for the same period in 2010.

During the six months ended June 30, 2011, the Company received cash distributions of $3.3 million on its B Unit investment in ACP II, as a result of ACP II's distribution to Avista of remaining 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 $2.9 million) were $14.1 million (or $0.77 per Mcfe) for the six months ended June 30, 2011 as compared to lease operating expenses (including transportation costs of $2.8 million) of $11.2 million (or $0.78 per Mcfe) for the six months ended June 30, 2010. Lease operating expenses increased due to increased production primarily attributable to new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation. Although we continued to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively less salt water disposal costs in the core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, this decrease was largely offset by increased operating cost per Mcfe associated with higher cost oil production.

Production taxes increased to $2.4 million (or 2.54% of revenues) for the six months ended June 30, 2011 from $1.8 million (or 2.49% of revenues) for the same period in 2010. The increases in production taxes and the percentage of revenues are due to increased oil production, which has a higher effective production tax rate as compared to natural gas.

Ad valorem taxes remained unchanged at $1.7 million for the six months ended June 30, 2011 and 2010. Ad valorem taxes for the first six months of 2011 includes a reduction to ad valorem taxes reflecting a true up of our estimated amounts to actual for 2010. This reduction was offset by increased ad valorem taxes associated with new oil and gas wells drilled in 2010. Ad valorem taxes per Mcfe decreased from $0.10 for the first six months of 2010 to $0.08 for the first six months of 2011 due primarily to this true up of the 2010 estimate.

General and administrative expenses were $10.7 million for the six months ended June 30, 2011 as compared to $8.7 million for the six months ended June 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in 2011.

DD&A expense for the six months ended June 30, 2011 increased to $37.3 million (or $1.70 per Mcfe) from $20.9 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 six 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 which were added during the fourth 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 $12.1 million for the six months ended June 30, 2011 compared to $6.1 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 Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

An unrealized loss on derivatives of $1.4 million was recorded for the six months ended June 30, 2011 compared to an unrealized gain on derivatives of $10.2 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 $10.7 million for the six months ended June 30, 2011 compared to $5.3 million for the same period in 2010. The increase was largely attributable to additional stock appreciation rights as well as stock appreciation rights that increased in fair value.

Non-cash interest expense, net of amounts capitalized, decreased to $1.6 million for the six months ended June 30, 2011 from $4.1 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 the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the six months ended June 30, 2011, we contributed $1.0 million in common stock to the Carrizo Oil & Gas, Inc. endowed scholarship fund at 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.

Our overall effective tax rate was 35.5% for the first six months of 2011 and 37.7% for the first six months of 2010. Our estimated annual effective income tax rate for 2011 is approximately 37%, substantially all of which we expect to be deferred. The effective income tax rate for the six months ended June 30, 2011 was lower than 37% due to the true up of prior estimates of the foreign tax benefit associated with the Company's UK Huntington field development.

Carrizo's President and CEO, S. P. "Chip" Johnson, IV, commented on recent activity, "In late July we initiated sales from a three well pad producing from the Eagle Ford Shale on our Mumme lease in La Salle County, Texas, and from our Orlando Hill well in the Niobrara Formation. These events marked an inflection point in our liquids production growth ramp. We anticipate the oil production from these new wells to be followed by a fairly steady increase for the remainder of the year, with each month's oil production sequentially higher than the last, as a sufficient inventory of drilled wells has been built in the Eagle Ford and Niobrara to allow the execution of a continuous completion program.

"While still flowing back significant quantities of completion fluid, the Mumme 30H, 31H and 32H have each reached rates between 920 BOE per day and 1,184 BOE per day, consisting of 720-984 barrels of oil and approximately 1,200 Mcf of high BTU natural gas which went directly to sales in the existing lease gas gathering system. Following stabilization, we intend to flow these wells at constrained rates to maximize ultimate recoveries. We expect to begin completion of a three well pad on the Glover lease in Atascosa County later this month and anticipate first sales to occur in mid-September. Our recently completed well in the Niobrara Formation, the Orlando Hill 26-44-8-61 in Weld County, Colorado, reached a peak 24 hour production rate of 650 bopd on July 17th and averaged 580 bopd over the following week. The Nelson 17-44-9-60 well has also been completed and is currently flowing back completion fluid with a strong oil cut. An additional Niobrara well, the Wickstrom 7-11-5-60, has been drilled to total depth and is scheduled for completion later this month. We continue to be satisfied with the results of our Niobrara program and expect to be able to average adding a new well to production each month for the rest of 2011.

"The production contribution from our Eagle Ford completion program and our Niobrara activity should allow us to exit the year 2011 at or above our previous guidance of 5,000 net bopd. This growth in liquids production, in addition to the improved well performance from the Barnett Shale, gives us confidence in meeting our 2011 production growth forecast of 32% (after adjustment for the sale of a portion of our Barnett Shale properties to KKR earlier this year)."

The Company will host a conference call to discuss 2011 second quarter financial results on Tuesday, August 9, 2011 at 10:00 AM Central Daylight Time. To participate in the call, please dial (800) 920-0677 ten minutes before the call is scheduled to begin. A replay of the call will be available through Friday, August 19, 2011 at 11:59 AM Central Daylight Time at (800) 633-8284. The conference ID for the replay is 21532914.

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 Second 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 natural 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, 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, production mix, completion program, 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)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2011 2010 2011 2010
Revenues:
Natural gas $ 31,840,299 $ 27,908,194 $ 60,851,024 $ 60,787,941
Oil and condensate 15,529,643 2,883,942 27,359,874 5,757,961
NGLs 3,301,804 2,129,469 6,519,223 5,331,844
Total oil and gas revenues 50,671,746 32,921,605 94,730,121 71,877,746
Realized gain on derivatives, net (1), (2) 3,387,107 10,534,986 12,180,549 15,457,308
Adjusted revenues 54,058,853 43,456,591 106,910,670 87,335,054
Costs and expenses:
Lease operating 7,426,810 6,166,742 14,093,404 11,242,225
Production taxes 1,466,398 885,548 2,407,024 1,790,328
Ad valorem taxes 981,231 467,831 1,672,123 1,672,160
General and administrative 5,700,606 4,272,874 10,703,171 8,669,754
Total costs and expenses 15,575,045 11,792,995 28,875,722 23,374,467
Other items of income (expense) included in EBITDA, as defined:
Cash Distributions-Related Party (3) 3,333,333 - 3,333,333 -
Other income (expense), net (3,731 ) (51,806 ) 57,232 (22,240 )
EBITDA, as defined $ 41,813,410 $ 31,611,790 $ 81,425,513 $ 63,938,347
EBITDA per common share-Basic $ 1.07 $ 0.93 $ 2.10 $ 1.96
EBITDA per common share-Diluted $ 1.06 $ 0.92 $ 2.06 $ 1.94
Other items of income (expense) included in adjusted net income, as defined:
Depreciation, depletion and amortization expense $ (20,594,783 ) $ (11,079,037 ) $ (37,271,201 ) $ (20,920,437 )
Cash interest expense (11,083,950 ) (5,904,195 ) (21,771,206 ) (11,815,516 )
Cash interest capitalized 5,022,490 2,993,754 9,624,240 5,687,495
Accretion expense related to asset retirement obligations (70,883 ) (52,576 ) (145,196 ) (103,861 )
Interest income 3,822 483 5,001 1,458
Adjusted income before income taxes 15,090,106 17,570,219 31,867,151 36,787,486
Adjusted income tax expense (5,544,105 ) (6,263,783 ) (11,707,991 ) (13,114,739 )
ADJUSTED net income, as defined $ 9,546,001 $ 11,306,436 $ 20,159,159 $ 23,672,747
ADJUSTED net income per common share-Basic $ 0.25 $ 0.33 $ 0.52 $ 0.73
ADJUSTED net income per common share-Diluted $ 0.24 $ 0.33 $ 0.51 $ 0.72
Other non-cash items of income (expense) included in net income:
Unrealized (gain) loss on derivatives, net (1), (2) $ 8,067,646 $ (7,419,784 ) $ (1,337,670 ) $ 10,207,491
Stock-based compensation expense (6,804,715 ) (3,156,324 ) (10,654,552 ) (5,320,331 )
Non-cash interest expense (1,323,151 ) (3,940,789 ) (2,843,604 ) (7,839,671 )
Non-cash interest capitalized 625,679 1,998,199 1,284,345 3,773,689
Non-cash reclassification of Cash Distributions-Related Party to oil and gas property costs (3) (3,333,333 ) - (3,333,333 ) -
Non-cash contribution expense (999,724 ) - (999,724 ) -
Loss on extinguishment of debt - - (896,850 ) -
Impairment of oil and gas properties - (2,730,882 ) - (2,730,882 )
Recoveries of (allowance for) doubtful accounts 21,504 (222,101 ) 53,567 (345,355 )
Income before income taxes 11,344,012 2,098,538 13,139,330 34,532,427
Income tax expense (3,602,377 ) (313,796 ) (4,662,089 ) (13,011,845 )
Net income $ 7,741,635 $ 1,784,742 $ 8,477,241 $ 21,520,582
Net income per common share-Basic $ 0.20 $ 0.05 $ 0.22 $ 0.66
Net income per common share-Diluted $ 0.20 $ 0.05 $ 0.21 $ 0.65
Weighted average common shares outstanding-Basic 38,898,363 34,060,228 38,841,166 32,573,905
Weighted average common shares outstanding-Diluted 39,496,686 34,463,791 39,450,381 33,021,636
NOTES:
(1) Includes reclassifications of approximately $.1 million and $.1 million for the three months ended June 30, 2011 and 2010, respectively and $.6 million and $.4 million for the six months ended June 30, 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. Includes reclassifications of approximately $.5 million for the three months and six months ended June 30, 2011, respectively, from general and administrative to unrealized gain/loss on derivatives, net, related to accrued agency fees incurred to enter into certain derivative positions.
(2) Includes reclassifications of approximately $1.4 million and ($1.8) million for the three months ended June 30, 2011 and 2010, respectively and $2.2 million and ($2.1) million for the six months ended June 30, 2011 and 2010, respectively, from unrealized gain (loss) on derivatives, net, to realized gain on derivatives, net, for cash received from the optimization of certain hedge positions that settle in future periods and the related non-cash amortization as such hedge positions settle.
(3) During the second quarter of 2011, the Company received cash distributions of $3.3 million 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 remaining proceeds from the sale of oil and gas properties to Reliance initially recorded 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, under the full cost method of accounting, such distributions are recognized as a reduction of oil and gas property costs.

CARRIZO OIL & GAS, INC.
CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
June 30, 2011 December 31, 2010
ASSETS:
Cash and cash equivalents $ 24,102 $ 4,128
Fair value of derivative instruments 17,754 17,698
Other current assets 44,949 38,506
Deferred income taxes 67,979 72,587
Property and equipment, net 1,066,496 983,057
Other assets 26,822 24,766
Investments 2,523 3,392
TOTAL ASSETS $ 1,250,625 $ 1,144,134
LIABILITIES AND SHAREHOLDERS' EQUITY:
Accounts payable and accrued liabilities $ 153,660 $ 109,651
Current maturities of long-term debt - 160
Other current liabilities 7,500 9,193
Long-term debt, net of current maturities and debt discount 607,009 558,094
Other liabilities 9,504 9,685
Fair value of derivative instruments 87 715
Shareholders' equity 472,865 456,636
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,250,625 $ 1,144,134

CARRIZO OIL & GAS, INC.
PRODUCTION VOLUMES AND PRICES
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2011 2010 2011 2010
Production volumes-
Oil and condensate (Bbls) 158,434 38,089 291,885 75,841
Natural gas (Mcfe) 9,802,968 8,722,525 19,282,070 16,318,818
NGLs (Mcfe) 420,107 344,114 832,250 788,239
Natural gas and NGLs (Mcfe) 10,223,075 9,066,639 20,114,320 17,107,057
Natural gas equivalent (Mcfe) 11,173,680 9,295,176 21,865,632 17,562,104
Average sales prices-
Oil and condensate ($ per Bbl) $ 98.02 $ 75.72 $ 93.74 $ 75.92
Oil and condensate ($ per Bbl) - with hedge impact $ 93.90 $ 93.30 $ 91.59 $ 84.75
Natural gas and NGLs ($ per Mcfe) $ 3.44 $ 3.31 $ 3.35 $ 3.87
Natural gas and NGLs ($ per Mcfe) - with hedge impact $ 3.83 $ 4.40 $ 3.99 $ 4.73
Natural gas equivalent ($ per Mcfe) $ 4.53 $ 3.54 $ 4.33 $ 4.09

Contact Information

  • Contact:
    Carrizo Oil & Gas, Inc.
    Richard Hunter
    Vice President of Investor Relations
    Paul F. Boling
    Chief Financial Officer
    (713) 328-1000