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EX-31.1 - CEO CERTIFICATION PURSUANT TO SECTION 302 - CARRIZO OIL & GAS INCexh311.htm
EX-32.1 - CEO CERTIFICATION PURSUANT TO SECTION 906 - CARRIZO OIL & GAS INCexh321.htm
EX-31.2 - CFO CERTIFICATION PURSUANT TO SECTION 302 - CARRIZO OIL & GAS INCexh312.htm
EX-32.2 - CFO CERTIFICATION PURSUANT TO SECTION 906 - CARRIZO OIL & GAS INCexh322.htm


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q

 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the quarterly period ended September 30, 2009


[  ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to _________


Commission File Number 000-29187-87

CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)

 
Texas
 
76-0415919
 
 
(State or other jurisdiction of
 
(IRS Employer Identification No.)
 
 
incorporation or organization)
     


1000 Louisiana Street, Suite 1500, Houston, TX
77002
(Address of principal executive offices)
(Zip Code)
   
(713) 328-1000
(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

YES [X]          NO [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES [ ]          NO [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer [X]    Accelerated filer []
 
 Non-accelerated filer [ ]         Smaller reporting company [ ]
 (Do not check if a smaller reporting company)  
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
YES [ ]          NO [X]

The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of November 2, 2009, the latest practicable date, was 31,072,006.
 


 

 
CARRIZO OIL & GAS, INC.

FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
INDEX



PART I.  FINANCIAL INFORMATION
PAGE
       
 
Item 1.
 
   
As of September 30, 2009 (Unaudited) and December 31, 2008
2
       
     
   
For the three and nine months ended September 30, 2009 and 2008
3
       
     
   
For the nine months ended September 30, 2009 and 2008
4
       
   
5
       
 
Item 2.
19
       
 
Item 3.
31
       
 
Item 4.
32
       
       
PART II.  OTHER INFORMATION
 
       
   
33
       
41
 

 
 
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
 
   
September 30,
   
December 31,
 
ASSETS
 
2009
   
2008
 
   
(Unaudited)
       
   
(In thousands, except par value amount)
 
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 3,576     $ 5,184  
Accounts receivable, trade (net of allowance for doubtful accounts of $1,552 and $1,264
         
at September 30, 2009 and December 31, 2008, respectively)
    21,228       24,675  
Advances to operators
    325       336  
Fair value of derivative financial instruments
    6,062       22,791  
Other current assets
    5,567       3,335  
Total current assets
    36,758       56,321  
                 
PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil and
               
natural gas properties (including costs not subject to amortization of $371,558 and
               
$378,634 at September 30, 2009 and December 31, 2008, respectively)
    878,646       986,629  
DEFERRED FINANCING COSTS, NET
    9,620       8,430  
INVESTMENTS
    3,577       3,274  
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
    -       15,876  
DEFERRED INCOME TAXES
    32,371       -  
OTHER ASSETS
    964       1,172  
TOTAL ASSETS
  $ 961,936     $ 1,071,702  
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
                 
CURRENT LIABILITIES:
               
Accounts payable, trade
  $ 50,922     $ 46,683  
Accrued liabilities
    30,632       54,149  
Advances for joint operations
    5,674       3,815  
Current maturities of long-term debt
    148       173  
Deferred tax liability
    2,197       9,103  
Total current liabilities
    89,573       113,923  
                 
LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT
    541,713       475,788  
ASSET RETIREMENT OBLIGATION
    9,902       6,503  
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
    5,915       -  
DEFERRED INCOME TAXES
    -       34,778  
OTHER LIABILITIES
    1,387       625  
                 
COMMITMENTS AND CONTINGENCIES
            -  
                 
SHAREHOLDERS' EQUITY:
               
Common stock, par value $0.01 (90,000 shares authorized; 31,056 and
               
30,860 issued and outstanding at September 30, 2009 and
               
December 31, 2008, respectively)
    311       309  
Additional paid-in capital
    428,960       420,778  
Retained earnings (deficit)
    (116,060 )     20,297  
Accumulated other comprehensive income (loss), net of tax
    235       (1,299 )
Total shareholders' equity
    313,446       440,085  
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
  $ 961,936     $ 1,071,702  
                 
The accompanying notes are an integral part of these consolidated financial statements.
 
-2-


CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(As Adjusted (See Note 2))

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands except per share amounts)
 
OIL AND NATURAL GAS REVENUES
  $ 23,847     $ 58,527     $ 81,221     $ 179,475  
                                 
COSTS AND EXPENSES:
                               
Oil and natural gas operating expenses (exclusive of depreciation, depletion
                               
and amortization shown separately below)
    5,213       10,427       22,837       28,047  
Third party gas purchases
    272       2,980       1,139       5,576  
Depreciation, depletion and amortization
    12,524       13,922       40,049       41,874  
Impairment of oil and gas properties
    -       -       216,391       -  
General and administrative (inclusive of stock-based compensation expense
                               
of $2,780 and $1,560 for the three months ended September 30, 2009 and
                               
2008, respectively, and $8,514 and $4,547 for the nine months ended
                               
September 30, 2009 and 2008, respectively)
    7,633       5,809       21,894       17,908  
Accretion expense related to asset retirement obligations
    79       58       225       173  
                                 
TOTAL COSTS AND EXPENSES
    25,721       33,196       302,535       93,578  
                                 
OPERATING INCOME (LOSS)
    (1,874 )     25,331       (221,314 )     85,897  
                                 
OTHER INCOME AND EXPENSES:
                               
Net gain (loss) on derivatives
    (1,986 )     77,686       25,802       (357 )
Loss on early extinguishment of debt
    -       16       -       (5,689 )
Interest income
    1       43       13       251  
Interest expense
    (9,903 )     (8,491 )     (28,617 )     (20,950 )
Capitalized interest
    4,996       6,315       15,065       14,479  
Impairment of investment in Pinnacle Gas Resources, Inc.
    -       -       (2,091 )     -  
Other income (expenses), net
    (23 )     15       16       64  
                                 
INCOME (LOSS) BEFORE INCOME TAXES
    (8,789 )     100,915       (211,126 )     73,695  
INCOME TAX (EXPENSE) BENEFIT
    3,994       (35,200 )     74,769       (26,056 )
                                 
NET INCOME (LOSS)
  $ (4,795 )   $ 65,715     $ (136,357 )   $ 47,639  
                                 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES:
                               
Increase (decrease) in market value of investment in Pinnacle Gas Resources, Inc.
    64       (3,684 )     179       (5,228 )
Reclassification of cumulative decrease in market value of investment in Pinnacle
                               
Gas Resources, Inc.
    -       -       1,359       -  
                                 
COMPREHENSIVE INCOME (LOSS)
  $ (4,731 )   $ 62,031     $ (134,819 )   $ 42,411  
                                 
BASIC INCOME (LOSS) PER COMMON SHARE
  $ (0.15 )   $ 2.15     $ (4.40 )   $ 1.59  
                                 
DILUTED INCOME (LOSS) PER COMMON SHARE
  $ (0.15 )   $ 2.12     $ (4.40 )   $ 1.56  
                                 
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
                               
BASIC
    31,053       30,531       30,980       30,005  
DILUTED
    31,053       30,973       30,980       30,452  
                                 
The accompanying notes are an integral part of these consolidated financial statements.
 
-3-

 
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(As Adjusted (See Note 2))

   
For the Nine
 
   
Months Ended
 
   
September 30,
 
   
2009
   
2008
 
   
(In thousands)
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income (loss)
  $ (136,357 )   $ 47,639  
Adjustment to reconcile net income (loss) to net cash provided by operating activities-
         
Depreciation, depletion and amortization
    40,049       41,874  
Impairment of oil and gas properties
    216,391       -  
Fair value (gain) loss of derivative financial instruments
    38,519       (13,933 )
Accretion of discounts on asset retirement obligations and debt
    225       173  
Stock-based compensation
    8,514       4,547  
Provision for allowance for doutbful accounts
    288       (166 )
Deferred income taxes
    (74,834 )     25,652  
Loss on extenguishment of debt
    -       4,601  
Amortization of equity premium associated with Convertible Senior Notes
    4,296       988  
Impairment of investment in Pinnacle Gas Resources, Inc.
    2,091       -  
Other
    4,857       3,550  
Changes in operating assets and liabilities
               
Accounts receivable
    3,158       (1,394 )
Other assets
    (1,548 )     (3,015 )
Accounts payable
    (2,053 )     6,847  
Accrued liabilities
    4,242       8,995  
Net cash provided by operating activities
    107,838       126,358  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures
    (143,036 )     (456,696 )
Change in capital expenditure accrual
    (21,309 )     (1,573 )
Proceeds from the sale of properties
    6       2,280  
Advances to operators
    12       (83 )
Advances for joint operations
    1,859       (453 )
Other
    (69 )     (2,771 )
Net cash used in investing activities
    (162,537 )     (459,296 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Net proceeds from debt issuance and borrowings
    100,037       590,034  
Debt repayments
    (43,886 )     (382,156 )
Proceeds from common stock offering, net of offering costs
    -       135,077  
Proceeds from stock options exercised
    9       240  
Deferred loan costs and other
    (3,069 )     (9,260 )
Net cash provided by financing activities
    53,091       333,935  
                 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (1,608 )     997  
                 
CASH AND CASH EQUIVALENTS, beginning of period
    5,184       8,026  
                 
CASH AND CASH EQUIVALENTS, end of period
  $ 3,576     $ 9,023  
                 
CASH PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)
  $ 2,659     $ 1,872  
                 
The accompanying notes are an integral part of these consolidated financial statements.
 
-4-

 
CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1.           SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles.  The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances.  The financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading.  The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2008.

Unconsolidated Investments

The Company accounts for its investment in Oxane Materials, Inc. using the cost method of accounting and adjusts the carrying amount of its investment for contributions to and distributions from the entity.

The Company’s investment in Pinnacle Gas Resources, Inc. is classified as available-for-sale.  The Company adjusts the book value to fair market value through other comprehensive income (loss), net of taxes.  If the impairment of the investment is considered other than temporary, the loss will be reclassified to the Statements of Operations from Other Comprehensive Income/Loss. Subsequent recoveries in fair value are reflected as increases to the Investments line item and Other Comprehensive Income (Loss).

Reclassifications

Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.  These reclassifications had no effect on total assets, total liabilities, shareholders’ equity or net income (loss).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported.  Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation.  Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, and also factor into the Company’s borrowing base and evaluation of the recoverability of deferred tax assets, have numerous inherent uncertainties.  The accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data.  Subsequent drilling, testing and production may justify revision of such estimates.  Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.  In addition, reserve estimates may be affected by changes in wellhead prices of crude oil and natural gas.  Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of oil and natural gas volumes, interest rates, the market value and volatility of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income.  Future changes in these assumptions may materially affect these significant estimates in the near term.  In particular, the Company owns interests in
 
-5-

 
approximately 2,630 gross acres in the Camp Hill Field in Anderson County, Texas, for which the Company reported approximately 8.2 MMBbls of proved reserves, including 5.0 MMBbls of proved undeveloped reserves (which represents approximately 6% of our total proved reserves) as of December 31, 2008. In connection with an ongoing review by the SEC’s staff of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, the staff has raised various issues regarding the classification of some of these reserves as proved.  The Company’s position that the Camp Hill proved reserves met the SEC’s definition of proved reserves continues to be subject to review.

In late 2008, the SEC adopted new rules regarding the classification of reserves that will become effective for the Company as of year-end of 2009, which, among other things, generally require proved undeveloped reserves to be developed within five years, unless specific circumstances justify a longer time.  As a result of various factors, including these new rules and our discussions with the SEC’s staff regarding their applicability to the Camp Hill Field, the Company may be required under applicable SEC rules to reclassify as unproved substantially all of our proved undeveloped reserves in the Camp Hill Field at year-end 2009 because these reserves will not be developed within the next five years.  The Company may also be required under applicable SEC rules to write-off or reclassify to proved undeveloped, a portion of our proved developed reserves.  This possible write-off of the reserves could significantly impact depletion expense, ceiling test impairment and the realizability of the net deferred tax asset.
 
The Company evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which the Company believes to be reasonable under the circumstances.  The Company adjusts such estimates and assumptions when facts and circumstances dictate.  The Company has evaluated subsequent events for recording and disclosure through November 9, 2009 – see Note 10.

Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the full-cost method of accounting.  All costs directly associated with the acquisition, exploration and development of oil and natural gas properties, including the Company’s gas gathering systems, are capitalized.  Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment.  The Company proportionally consolidates its interests in oil and natural gas properties.  The Company capitalized employee-related costs for employees working directly on exploration activities of $4.1 million and $5.2 million for the nine months ended September 30, 2009 and 2008, respectively.  Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and natural gas properties is based on the unit-of-production method using estimates of proved reserve quantities.  Costs not subject to amortization include costs of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and exploratory wells in progress.  These costs are evaluated periodically for impairment on a property-by-property basis.  If the results of an assessment indicate that the properties have been impaired, the amount of such impairment is determined and added to the proved oil and natural gas property costs subject to DD&A.  The depletable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values.  The depletion rate per Mcfe for the quarters ended September 30, 2009 and 2008 was $1.50 and $2.24, respectively.

Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

Net capitalized costs are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves, based on current economic and operating conditions.  If net capitalized costs exceed this limit, the excess is charged to earnings.  During the nine-month period ended September 30, 2009, the Company incurred an impairment charge of $216.4 million ($138.0 million net of tax).  For the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by current SEC guidelines, to measure the full cost ceiling test impairment.  Using prices as of May 6, 2009, the Company incurred an impairment charge of $216.4 million ($138.0 million net of tax).  Had the Company used prices in effect as of March 31, 2009, an impairment of $323.2 million ($206.1 million net of tax) would have been recorded for the first quarter of 2009.  The option to use a pricing date subsequent to the balance sheet will no longer be available to the Company starting December 31, 2009 due to the adoption of the new oil and natural gas reporting requirements as described below under “Recently Issued Accounting Pronouncements.”

Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years.

Supplemental Cash Flow Information

The Company paid less than $100,000 in income taxes during the nine months ended September 30, 2009 and 2008.

-6-

 
Stock-Based Compensation

The Company issues restricted stock and stock options, including stock appreciation rights (“SAR”), as compensation to employees, directors and certain contractors.  Restricted stock is measured at grant date fair value and recorded as deferred compensation based on the average of the high and low prices of the Company’s stock on the issuance date and is amortized to stock-based compensation expense ratably over the vesting period of the restricted shares (generally one to three years).  Stock option compensation, including SAR, is based on the grant-date fair value of the options and is recognized over the vesting period.

The Company recognized the following stock-based compensation expense for the three and nine months ended September 30:

   
Three Months
   
NineMonths
 
   
Ended September 30,
   
Ended September 30,
 
   
2009(1)
   
2008
   
2009(1)
   
2008
 
   
(In millions)
 
Stock Option Expense
  $ 0.3     $ -     $ 0.4     $ 0.2  
Restricted Stock Expense
    2.5       1.5       8.1       4.3  
                                 
Total Stock-Based Compensation Expense
  $ 2.8     $ 1.5     $ 8.5     $ 4.5  
                                 
__________
(1)  
In 2009, the Company issued stock-based awards that vested in less than six months from grant date in lieu of annual and quarter cash bonuses.
 
General and Administrative Expenses

The Company recognizes and classifies general and administrative expenses as incurred and as required by accounting guidelines, including infrequent and/or non-cash items.  The table below identifies the non-cash and/or unusual items included in general and administrative expenses:

   
Three months ended
   
Nine months ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(In millions)
 
Stock-based compensation
  $ 2.8     $ 1.5     $ 8.5     $ 4.5  
Non-cash charitable contribution(1)
    0.9       -       0.9       -  
Bad debt expnse
    -       -       0.3       (0.2 )
                                 
    $ 3.7     $ 1.5     $ 9.7     $ 4.3  
                                 
__________
(1)  
During the third quarter of 2009, the Company pledged $1.0 million to the University of Texas at Arlington, of which it paid $0.1 million in cash.  The Company recognized the entire pledge in the period incurred.

Derivative Instruments

The Company uses derivatives to manage price risk underlying its oil and natural gas production.  The Company also used derivatives to manage the variable interest rate on its borrowings under the second lien credit facility, which was terminated in May 2008.

Upon entering into a derivative contract, the Company either designates the derivative instrument as a hedge of the variability of cash flow to be received (cash flow hedge) or the derivative must be accounted for as a non-designated derivative.  All of the Company’s derivative instruments are treated as non-designated derivatives and the unrealized gain (loss) related to the mark-to-market valuation is included in the Company’s earnings.

The Company typically uses fixed-rate swaps, costless collars, puts and calls to hedge its exposure to material changes in the price of oil and natural gas.
 
-7-

 
The Company’s Board of Directors sets all risk management policies and reviews volumes, types of instruments and counterparties on a quarterly basis.  These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board.  The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades.  The Board of Directors also reviews the status and results of derivative activities at least quarterly.

Major Customers

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

   
Three Months
   
Nine Months
 
   
Ended September 30,
   
Ended September 30,
 
   
2009
   
2008
   
2009
   
2008
 
Cokinos Natural Gas Company
    10 %     11 %     10 %     11 %
Crosstex Energy Services, Ltd.
    -       10 %     -       11 %
DTE Energy Trading, Inc.
    48 %     37 %     53 %     36 %
                                 
Earnings Per Share

Supplemental earnings per share information is provided below:

   
Three Months
   
Nine Months
 
   
Ended September 30,
   
Ended September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands, except
 
   
per share amounts)
 
Net income (loss)
  $ (4,795 )   $ 65,715     $ (136,357 )   $ 47,639  
                                 
Average common shares outstanding
                               
Weighted average common shares outstanding(1)
    31,053       30,531       30,980       30,005  
Stock options and warrants
    -       442       -       447  
Diluted weighted average common shares outstanding
    31,053       30,973       30,980       30,452  
                                 
Net income (loss) per common share(1)
                               
Basic
  $ (0.15 )   $ 2.15     $ (4.40 )   $ 1.59  
Diluted
  $ (0.15 )   $ 2.12     $ (4.40 )   $ 1.56  
                                 
__________
(1)  
In January 2009, the Company adopted and retroactively applied new accounting guidelines associated with restricted stock and participating securities.  The Company determined that all of its shares of restricted stock are participating securities and should be included in the basic earnings per share calculation (see Note 2 for additional details).

Basic earnings per common share is based on the weighted average number of shares of common stock (including restricted stock) outstanding during the periods.  Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares issuable during the periods.  The Company did not include options to purchase 893,837 shares in the calculation of dilutive shares for the three and nine months ended September 30, 2009 due to the net loss reported in the periods.  Shares of common stock subject to issuance pursuant to the conversion features of the 4.375% Convertible Senior Notes due 2028 (the “Convertible Senior Notes”) did not have an effect on the calculation of dilutive shares for the three and nine months ended September 30, 2009 and 2008.

-8-

 
Asset Retirement Obligation

The following table is a reconciliation of the asset retirement obligation liability:

   
Nine Months Ended
   
Year Ended
 
   
September 30,
   
December 31,
 
 
 
2009
   
2008
 
 
 
(In thousands)
 
Asset retirement obligation at beginning of year
  $ 6,503     $ 5,869  
Liabilities incurred
    239       1,004  
Liabilities settled
    (12 )     (177 )
Accretion expense
    225       154  
Revisions to previous estimates
    2,947       (347 )
Asset retirement obligation at end of year
  $ 9,902     $ 6,503  
                 
 
The $2.9 million revision to previous estimates relates primarily to location clean up costs in the Barnett Shale area.

Income Taxes

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers future taxable income based upon the Company’s estimated production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the deferred tax assets are reduced by a valuation allowance.

Recently Adopted Accounting Pronouncements

On January 1, 2009, the Company adopted new accounting guidelines related to convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion.  Under the accounting guidelines, issuers of convertible debt are required to separately account for the liability and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods.  The new accounting guidelines require retrospective application to the terms of instruments as they existed for periods presented.  The Company retrospectively applied the accounting guidelines to the Convertible Senior Notes.  The Company valued the conversion premium of the convertible debt at $64.2 million and accordingly restated its balance sheet as of December 31, 2008 for the carrying value of debt and equity and restated its results of operations for interest expense, capitalized interest, and income taxes for the year ended December 31, 2008.  See Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.

On January 1, 2009, the Company adopted and retroactively applied new accounting guidelines related to restricted stock and participating securities.  Under the new accounting treatment, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share.  These new guidelines require retroactive application for all periods presented.  The Company determined that its restricted shares of common stock are participating securities and applied the new accounting treatment retrospectively to all periods presented.  See Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.

In March 2008, new guidance for derivative disclosures was issued and requires transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  The Company adopted these requirements effective January 1, 2009 and they did not have a significant effect on the Company’s consolidated financial position, results of operations or cash flows.

In April 2009, additional guidance for estimating fair value was finalized.  The Company adopted this pronouncement effective June 30, 2009, and it had no material impact on the Company’s consolidated financial statements.

In April 2009, guidance on the recognition of other-than-temporary impairments of investments in debt securities was issued and provides new presentation and disclosure requirements for other-than-temporary impairments of investments in debt and equity
 
-9-

 
securities.  The Company adopted the requirements of this pronouncement effective June 30, 2009, and it had no material impact on the Company’s consolidated financial statements.

In April 2009, accounting rules were amended to require disclosure about fair value of financial instruments in interim reporting periods, as well as in annual financial statements.  The Company adopted the requirements of this pronouncement effective June 30, 2009, and included the additional disclosures in the Company’s Notes to Consolidated Financial Statements.

In May 2009, general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued were established to set forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.  The Company applied the requirement of this pronouncement effective June 30, 2009, and included additional disclosures in the Company’s Notes to Consolidated Financial Statements.

In June 2009, the Financial Accounting Standards Board established the Accounting Standards Codification (Codification), which became effective July 1, 2009, as the single source of authoritative U.S. GAAP to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All other accounting literature excluded from the Codification will be considered nonauthoritative. The subsequent issuances of new standards will be in the form of Accounting Standards Updates that will be included in the Codification. Generally, the Codification is not expected to change U.S. GAAP.  The Company adopted the Codification effective September 30, 2009 and updated its disclosure references accordingly.

Recently Issued Accounting Pronouncements

On December 31, 2008, the SEC adopted major revisions to its rules governing oil and gas company reporting requirements. These new rules will permit the use of new technologies to determine proved reserves and allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserves estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.  Changes in reserve amounts could significantly impact depletion expense, ceiling test impairment and recoverability of deferred tax assets.  For more information, see “Use of Estimates,” discussed above.

2.  
ADJUSTMENT FOR IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENT

On January 1, 2009, the Company adopted new accounting guidelines related to convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion.  Under these guidelines, issuers of convertible debt are required to separately account for the liability and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods.  The new accounting treatment requires retrospective application to the terms of instruments as they existed for periods presented.  The retrospective application of this accounting pronouncement affects the Company’s results of operations for the periods during December 31, 2008 as it relates to the Company’s Convertible Senior Notes.

On January 1, 2009, the Company adopted and retroactively applied new accounting guidelines related to restricted stock and participating securities.  Under the new accounting treatment, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and will be included in the computation of both basic and diluted earnings per share.  The Company determined that its restricted shares of common stock are participating securities and applied this accounting treatment retroactively to all periods presented.

The following table sets forth the effect of the retrospective application of the new accounting guidelines for convertible debt and unvested share-based payment awards on certain previously reported items.

-10-

 
Consolidated Statement of Income:

   
For the three months
   
For the nine months
 
   
ended September 30, 2008
   
ended September 30, 2008
 
   
Originally
   
As
   
Originally
   
As
 
   
Reported
   
Adjusted
   
Reported
   
Adjusted
 
   
(In thousands, except per share amounts)
 
Interest expense
    5,297       8,491       16,694       20,950  
Capitalized interest
    3,866       6,315       11,211       14,479  
Income tax expense
    35,461       35,200       26,402       26,056  
Net income (loss)
    66,199       65,715       48,281       47,639  
                                 
Basic Income Per Share
  $ 2.18     $ 2.15     $ 1.62     $ 1.59  
Diluted Income Per Share
  $ 2.14     $ 2.12     $ 1.59     $ 1.56  
                                 
Weighted Average Common Shares Oustanding
                         
  Basic
    30,424       30,531       29,842       30,005  
  Diluted
    30,973       30,973       30,452       30,452  
                                 
3.  
LONG-TERM DEBT

Long-term debt consisted of the following at September 30, 2009 and December 31, 2008:

   
September 30,
   
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
Convertible Senior Notes
  $ 373,750     $ 373,750  
Unamortized discount for Convertible Senior Notes
    (48,197 )     (57,269 )
Senior Secured Revolving Credit Facility
    216,000       159,000  
Other
    308       480  
      541,861       475,961  
  Current maturities
    (148 )     (173 )
                 
    $ 541,713     $ 475,788  
                 
Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of the Convertible Senior Notes.  Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process, into a combination of cash and Carrizo common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of the Company’s conversion obligation in excess of such principal amount.

The notes are convertible into the Company’s common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate).

Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of Carrizo common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of Carrizo common stock are made or
 
-11-

 
specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after June 30, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028.

The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility (defined below), the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.

The Convertible Senior Notes are unsecured obligations of the Company and rank equal to all future senior unsecured debt but rank second in priority to the Senior Credit Facility.

In accordance with the accounting guidelines for convertible debt, the Company valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium.  The resulting debt discount will be amortized to interest expense through June 1, 2013, the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, and will result in an effective interest rate of approximately 8% for the Convertible Senior Notes.

Senior Secured Revolving Credit Facility

On May 25, 2006, the Company entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent. The Senior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially all of the Company’s proved oil & gas assets and is currently guaranteed by certain of the Company’s subsidiaries:  CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus), LLC; Carrizo Marcellus Holdings, Inc.; Chama Pipeline Holding, LLC and Hondo Pipeline Inc.

In the fourth quarter of 2008, the Company amended the Senior Credit Facility to, among other things, (a) extend the maturity date to October 29, 2012; (b) change the semi-annual borrowing base redetermination dates to March 31 and September 30; and (c) replace JPMorgan Chase Bank with Guaranty Bank as the administrative agent bank.

In April 2009, the Company amended the Senior Credit Facility to, among other things, (a) adjust the maximum ratio of total net debt to Consolidated EBITDAX; (b) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDAX to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component under the accounting guidelines related to convertible debt that may be settled in cash (including partial cash settlement) upon conversion:  $51,252,980 during 2009, $38,874,756 during 2010, $26,021,425 during 2011 and $12,674,753 during 2012 until the maturity date; (c) add a new senior leverage ratio; (d) modify the interest rate margins applicable to Eurodollar loans; (e) modify the interest rate margins applicable to base rate loans; and (f) establish new procedures governing the modification of swap agreements.

In May 2009, the Company amended the Senior Credit Facility to, among other things, (1) replace Guaranty Bank with Wells Fargo Bank, N.A. as administrative agent, (2) provide that the aggregate notional volume of oil and natural gas subject to swap agreements may not exceed 80% of “forecasted production from proved producing reserves,” (as that term is defined in the Senior Credit Facility), for any month, (3) remove a provision that limited the maximum duration of swap agreements permitted under the Senior Credit Facility to five years, and (4) provide that the aggregate notional amount under interest rate swap agreements may not exceed the amount of borrowings then outstanding under the Senior Credit Facility.  Also in April 2009, the Company amended the Senior Credit Facility to increase the borrowing base to $290,000,000 and, in May 2009, the total commitment of the lenders was increased from $250,000,000 to $259,400,000.  On June 5, 2009, the total commitment was increased by $25,000,000 to $284,400,000 with the addition of a new lender to the bank syndicate.

If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, the Company has the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period.
 
-12-

 
Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.

The annual interest rate on each base rate borrowing is (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the adjusted Daily LIBO rate on such day plus a margin between 2.25% to 3.25% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted daily LIBO rate plus a margin between 2.25% to 3.25% (depending on the then-current level of borrowing base usage). At September 30, 2009, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.3%.

The Company is subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.00 to 1.00; and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of (a) 4.25 to 1.00 for the quarter ending June 30, 2009, (b) 4.50 to 1.00 for the quarter ending September 30, 2009, (c) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (d) 4.25 to 1.00 for the quarter ending December 31, 2010, and (e) 4.00 to 1.00 for each quarter ending on or after March 31, 2011; and (3) a maximum ratio of senior debt (which excludes debt attributable to the Convertible Senior Notes) to Consolidated EBITDAX of 2.25 to 1.00.

Although the Company currently believes that it can comply with all of the financial covenants with the business plan that it has put in place, the business plan is based on a number of assumptions, the most important of which is a relatively stable, natural gas price at economically sustainable levels. If the price that the Company receives for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants in the Senior Credit Facility, including the financial covenants discussed above. In order to provide a further margin of comfort with regards to these financial covenants, the Company may seek to further reduce its capital and exploration budget, sell non-strategic assets, opportunistically modify or increase its natural gas hedges or approach the lenders under our Senior Credit Facility for modifications of either or both of the financial covenants discussed above. There can be no assurance that the Company will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our Senior Credit Facility if a precipitous decline in natural gas prices were to occur in the future. The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.

The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.

At September 30, 2009, the Company had $216.0 million of borrowings outstanding under the Senior Credit Facility and the amount available for borrowings was $68.4 million.

4.  
INVESTMENTS

Investments consisted of the following at September 30, 2009 and December 31, 2008:

   
September 30,
 
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
Pinnacle Gas Resources, Inc.
  $ 1,054     $ 751  
Oxane Materials, Inc.
    2,523       2,523  
                 
    $ 3,577     $ 3,274  
                 
Pinnacle Gas Resources, Inc.

In 2003, the Company and its wholly-owned subsidiary CCBM, Inc. contributed their interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”).  As of September 30, 2009, the Company owned 2,510,324 shares of Pinnacle common stock.

-13-

 
The Company classifies the Pinnacle investment as available-for-sale and adjusts the investment to fair value through other comprehensive income.  At September 30, 2009, the Company reported the fair value of the stock at $1.1 million (based on the closing price of Pinnacle’s common stock on September 30, 2009).  At March 31, 2009, the market value of the Company’s investment in Pinnacle had consistently remained below its original book basis since October 2008.  The Company determined that the impairment was other than temporary, and accordingly, recorded an impairment expense of $2.1 million at March 31, 2009.

Oxane Materials, Inc.

In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program.  The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant.  The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane.  The convertible promissory note accrued interest at a rate of 6% per annum.  During the fourth quarter of 2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock.  The Company accounts for the investment using the cost method.

5.  
INCOME TAXES

The income tax expense (benefit) for the indicated periods was different than the amount computed using the federal statutory rate (35%) for the following reasons:
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
Amount computed using the statutory rate
  $ (3,076 )   $ 35,320     $ (73,894 )   $ 25,793  
Increase (decrease) in taxes resulting from:
                               
State and local income taxes, net of federal effect
    (109 )     21       (2,618 )     399  
Other(1)
    (809 )     (141 )     1,743       (136 )
Total income tax expense (benefit)
  $ (3,994 )   $ 35,200     $ (74,769 )   $ 26,056  
                                 
__________
(1)  
Includes a tax benefit of $0.9 million and a tax expense of $1.7 million for the three and nine months ended September 30, 2009, respectively, related to prior period state income taxes that were not recorded.  The Company has concluded these amounts are not material to the current or prior financial statements.

At September 30, 2009, the Company had a net deferred tax asset of $30.2 million.  The Company has determined it is more likely than not that its deferred tax assets are fully realizable based on projections of future taxable income which included estimated production of proved reserves at estimated future pricing.  No valuation allowance for the net asset is currently needed.

The Company classifies interest and penalties associated with income taxes as interest expense.  At September 30, 2009, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

6.  
COMMITMENTS AND CONTINGENCIES

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business.  While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a material adverse effect on the operations or financial position of the Company.

The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights.  Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.
 
-14-

 
7.  
SHAREHOLDERS’ EQUITY

The following is a summary of changes in the Company’s common stock for the nine-month periods ended September 30:

   
2009
   
2008
 
   
(In thousands)
 
Shares outstanding at January 1
    30,860       28,009  
Equity offering
    -       2,588  
Restricted stock issued, net of forfeitures
    179       98  
Employee stock options exercised
    5       58  
Common stock issued for oil and gas properties
    10       -  
Common stock repurchased and retired for tax withholding obligation
    -       (6 )
Shares outstanding at September 30
    31,054       30,747  
                 
In February 2008, the Company completed an underwritten public offering of 2,587,500 shares of its common stock at a price of $54.50 per share.  The number of shares sold was approximately 9.2% of the Company’s outstanding shares before the offering.  The Company received proceeds of approximately $135.1 million, net of expenses.

8.  
DERIVATIVE INSTRUMENTS

The Company enters into swaps, options, collars and other derivative contracts to manage price risks associated with a portion of anticipated future oil and natural gas production.  Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company enters into the majority of its derivative transactions with three counterparties and netting agreements are in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the financial instruments. The Company also used interest rate swap agreements to manage the Company’s exposure to interest rate fluctuations on borrowings under the Company’s second lien credit facility, which was terminated in May 2008.

The Company accounts for its oil and natural gas derivatives and interest rate swap agreements as non-designated hedges.  These derivatives are marked-to-market at each balance sheet date and the unrealized gains (losses) along with the realized gains (losses) associated with the settlements of derivative instruments are reported as net gain (loss) on derivatives, in other income and expenses in the Consolidated Statements of Operations.  For the three and nine months ended September 30, 2009 and 2008, the Company recorded the following related to its derivatives:
 
-15-


   
Three Months
   
Nine Months
 
   
Ended September 30,
   
Ended September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(In millions)
 
Realized gains (losses):
                       
Natural gas and oil derivatives
  $ 18.7     $ 1.3     $ 64.3     $ (9.0 )
Interest rate swaps - Second Lien Debt Outstanding
    -       -       -       (1.2 )
Loss on interest rate swap settlement related to
                               
Second Lien Credit Facility
    -       -       -       (3.3 )
      18.7       1.3       64.3       (13.5 )
                                 
Unrealized gains (losses):
                               
Natural gas and oil derivatives
    (20.7 )     76.4       (38.5 )     10.4  
Interest rate swaps
    -       -       -       2.8  
      (20.7 )     76.4       (38.5 )     13.2  
                                 
Net gain (loss) on derivatives
  $ (2.0 )   $ 77.7     $ 25.8     $ (0.3 )
                                 
 
At September 30, 2009, the Company had the following outstanding derivative positions:

   
Natural Gas
   
Natural Gas
 
   
Swaps
   
Collars
 
         
Average
         
Average
   
Average
 
Quarter
 
MMBtus(1)
   
Fixed Price(2)
   
MMBtus(1)
   
Floor Price(2)
   
Ceiling Price(2)
 
Fourth Quarter 2009
    3,680,000       5.58       2,576,000       7.17       8.90  
First Quarter 2010
    3,150,000       5.45       1,620,000       7.92       9.63  
Second Quarter 2010
    3,185,000       5.50       637,000       5.84       7.30  
Third Quarter 2010
    1,840,000       5.57       1,104,000       6.07       7.62  
Fourth Quarter 2010
    1,840,000       5.57       1,380,000       6.49       7.90  
First Quarter 2011
    1,800,000       5.64       450,000       9.70       11.70  
Second Quarter 2011
    1,820,000       5.64       455,000       8.25       10.25  
Third Quarter 2011
    1,840,000       5.64       460,000       8.65       10.65  
Fourth Quarter 2011
    1,840,000       5.64       460,000       8.85       10.85  
First Quarter 2012
    910,000       5.88       455,000       9.55       11.55  
Second Quarter 2012
    910,000       5.88       455,000       8.35       10.35  
Third Quarter 2012
    920,000       5.88       -       -       -  
Fourth Quarter 2012
    920,000       5.88       -       -       -  
      24,655,000               10,052,000                  
                                         
__________
(1)  
During 2009, the Company entered into (i) a $5.35 put, a $6.20 long-call and an $8.00 short-call with respect to a portion of the Company’s production hedged with swaps (10,000 MMBtus per day) in 2011 and 2012 and (ii) a $4.35 put, a $6.00 long-call and a $6.50 short-call with respect to a portion of the Company’s production hedged with swaps (20,000 MMBtus per day) for April through October of 2010.  The table below presents additional put positions the Company has entered into associated with a portion of hedged volumes presented above:
 
-16-

 
Quarter
 
MMBtus
   
Put Price(2)
 
Fourth Quarter 2009
    1,530,000       2.39  
Second Quarter 2010
    455,000       3.74  
Third Quarter 2010
    920,000       4.31  
Fourth Quarter 2010
    1,196,000       4.61  
First Quarter 2011
    900,000       5.90  
Second Quarter 2011
    910,000       5.90  
Third Quarter 2011
    920,000       5.90  
Fourth Quarter 2011
    920,000       5.90  
First Quarter 2012
    455,000       6.80  
Second Quarter 2012
    455,000       6.80  
                 
__________
(1)  
Based on Houston Ship Channel (“HSC”) and WAHA spot prices.

At September 30, 2009, approximately 53% of the Company’s open natural gas hedged volumes were with Credit Suisse, and the remaining 47% were with Shell Energy North America (US), L.P.  In addition, the Company entered into put options for 2,745,000 MMBtus with Calyon Credit Agricole CIB covering certain production from October through December 2009 and January through December 2011.

The fair value of the outstanding derivatives at September 30, 2009 and December 31, 2008 was a net asset of $0.2 million and $38.7 million, respectively.

9.  
FAIR VALUE MEASUREMENTS

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in thousands)
 
Assets:
                       
Investment in Pinnacle Gas Resources, Inc.
  $ 1,054     $ -     $ -     $ 1,054  
Oil and natural gas derivatives
    -       6,062       -       6,062  
Liabilities:
                               
Oil and natural gas derivatives
    -       (5,915 )     -       (5,915 )
                                 
Total
  $ 1,054     $ 147     $ -     $ 1,201  
                                 
Oil and natural gas derivatives are valued by using valuation models that are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

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Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and bank borrowings, including borrowings under the Senior Credit Facility. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of September 30, 2009 and December 31, 2008, and were determined based upon interest rates currently available to the Company for borrowings with similar terms.  The fair value of the Convertible Senior Notes at September 30, 2009 was estimated at approximately $303.7 million.

10.  
 SUBSEQUENT EVENTS

In October 2009, the Company sold its Mansfield pipeline and gathering system in the Barnett Shale play for approximately $34.7 million, including a working capital adjustment of approximately $1.2 million.  The net proceeds were used to reduce the debt outstanding under the Senior Credit Facility.
 
-18-

 
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying unaudited financial statements.  You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements included in our Annual Report on Form 10-K/A for the year ended December 31, 2008 and the unaudited financial statements included in this quarterly report.

General Overview

Our third quarter 2009 included revenues of $23.8 million and production of 8.2 Bcfe.  The key drivers to our results for the three and nine months ended September 30, 2009 included the following:

Drilling program.  Our success is largely dependent on the results of our drilling program.  During the nine months ended September 30, 2009, we drilled (1) 37 gross wells (26.4 net wells) in the Barnett Shale area with an apparent success rate of 100%, (2) one of two gross (0.3 net) wells in the Gulf Coast and (3) two gross (0.6 net) wells in the Marcellus Shale.  At September 30, 2009 we had an inventory of 42 gross wells (31.6 net) in the Barnett Shale that have been drilled and are waiting on hydraulic fracturing, completion or hook-up to sales.

Production.  Our third quarter 2009 production of 8.2 Bcfe, or 89.2 MMcfe/d was a 37% increase from the third quarter 2008 production of 6.0 Bcfe, or 65.0 MMcfe/d.  The third quarter 2009 production increased 4% from the second quarter 2009 production of 7.9 Bcfe primarily due to new production.

Commodity prices.  Our average natural gas price during the third quarter of 2009 was $2.60 per Mcf (excluding the impact of our hedges), $6.17 per Mcf, or 70%, lower than the price in the third quarter of 2008 and $0.47 per Mcf, or 15%, lower than the price in the second quarter of 2009.  

Financial flexibility.  In April 2009, we improved our financial flexibility through an amendment to our senior secured revolving credit facility (the “Senior Credit Facility”) that (a) increased the maximum total debt leverage ratio under the Senior Credit Facility through 2010 to as high as 4.75 to 1, (b) refined the definition of Net Debt in the leverage ratio to exclude a portion of our 4.375% Senior Convertible Notes due 2028 (the “Senior Convertible Notes”) (starting at $51 million in 2009) and (c) added a senior debt leverage covenant with a maximum ratio of 2.25 to 1.  In addition, the borrowing base under the Senior Credit Facility was increased to $290 million and, on June 5, 2009, the total commitments of the lenders were increased to $284.4 million.  See “Senior Credit Facility” for more information.  In October 2009, we sold certain of our pipeline gathering systems in the Barnett Shale for approximately $34.7 million.  The net proceeds from the sale of this pipeline system were used to reduce the debt outstanding under the Senior Credit Facility.  See “Recent Events – Mansfield Pipeline Sale.”

Recent Events

Camp Hill Field Operational Update

Development activities continued at our Camp Hill Field during the course of the third quarter of 2009.  Consistent with our prior disclosure in our Annual Report on Form 10-K/A for the year-ended December 31, 2008, we have completed the refurbishment of one steam generator for use in the field and continue to refurbish two others.  Over the last three months, eight injection and seven production wells drilled in 2008 were completed and eight new steam lines were laid to injection wells.

Steam injection from one generator recommenced in the Camp Hill Field on September 14, 2009, with steam flowing into six newly completed injection wells in an area of the field that has never been previously steam flooded, as well as in seven existing patterns that were steamed on a pilot basis in the latter half of 2008.  We expect to complete and connect 11 additional injector wells to steam lines during the fourth quarter of 2009. Heavy oil production from the Camp Hill Field for the month of August was 1,405 barrels, and we expect October production to be approximately 1,800 barrels, with additional improvement in production rates expected as the reservoir heats up in response to the steaming.

-19-

 
Mansfield Pipeline Sale

We sold our Mansfield pipeline and gathering system in the Barnett Shale play to Delphi Midstream Partners, LLC (“Delphi”) for net proceeds of $34.7 million, including a working capital adjustment of approximately $1.2 million.  Net proceeds from the sale were used to reduce the debt outstanding under the Senior Credit Facility.  We constructed the Mansfield pipeline system to gather and transport natural gas from our Southeast Tarrant County operating area.  The pipeline consists of 19 miles of 6, 8 and 10 inch diameter pipe with a current maximum takeaway capacity of 70 MMcf/day.  The system also includes an associated compression/dehydration facility that was included in the transaction.  Over the 30 days preceding the date of sale, the pipeline transported an average of 55 MMcf/day.  We have also entered into an agreement to continue to operate the Mansfield pipeline system on Delphi’s behalf.

Northeast Pennsylvania Alliance

We have entered into an alliance with Delphi through which the parties have agreed to cooperate in solving gathering and mid-stream pipeline related issues for our Marcellus production in certain Northeast Pennsylvania counties including, among others, Bradford, Susquehanna, Tioga, Wayne and Wyoming counties.  We have granted Delphi a right of first offer with respect to Northeast Pennsylvania if we seek to find a third party to develop and construct a gathering or intrastate pipeline and a right of first refusal with respect to Wyoming County if a third party other than Delphi makes a development proposal.  This alliance will terminate on the earlier to occur of October 19, 2014 or the date that Delphi invests $100 million to develop and construct pipelines under the alliance.

Outlook

Our outlook for 2009 remains challenging as near-term natural gas futures prices for the remainder of 2009 remain low and possibly could decline further but the outlook for our long-term future remains positive.  Production growth, preservation of liquidity and stable upward movement in commodity prices are key to our future success.  We believe the following measures will continue to have a positive impact on our 2009 results:

·  
We plan to continue efforts to control capital costs.  During the first nine months of 2009, excluding capitalized interest and overhead, we spent approximately $105 million of capital expenditures on our drilling program and $21.1 million on leasehold and seismic costs.   Based upon our current outlook for operational performance in the remainder of 2009, we have revised our 2009 capital and exploration plan to approximately $155.0 million, which we currently expect to fund through cash generated from our operations, cash available under the Senior Credit Facility or from sales of assets, including our Mansfield pipeline system.  For a further discussion of our 2009 capital budget and funding strategy, see “Liquidity and Capital Resources—2009 Capital Budget and Funding Strategy” and “Liquidity and Capital Resources—Sources and Uses of Cash.”

·  
We plan to continue the exploration and development activities in the Marcellus Shale in the Northeastern United States, primarily through joint ventures with ACP II Marcellus, LLC and with other industry partners.  Among other activities, we currently plan to drill five gross (2.4 net) vertical wells in the Virginia and West Virginia parts of the Marcellus Shale to test the prospectivity of that area.  In the later part of 2009, we started drilling two wells in Pennsylvania and plan to drill a third well pending further seismic data interpretation.

·  
We expect to continue to hedge production to limit our exposure to reductions in natural gas prices.  At September 30, 2009, we had hedged approximately 34,707,000 MMBtus of natural gas production through 2012.

Results of Operations

Three Months Ended September 30, 2009,
Compared to the Three Months Ended September 30, 2008

Revenues from oil and natural gas production for the three months ended September 30, 2009 decreased 57% to $23.6 million from $55.4 million for the same period in 2008 due to declining oil and natural gas prices.  Production volumes for natural gas for the three months ended September 30, 2009 increased 39% to 7.9 Bcf from 5.7 Bcf for the same period in 2008.  Average natural gas prices, excluding the impact of our cash-settled derivatives comprised of a $18.7 million and a $1.6 million gain for the quarters ended September 30, 2009 and 2008, respectively, decreased to $2.60 per Mcf in the third quarter of 2009 from $8.78 per Mcf in the same period in 2008.  Average oil prices, excluding the impact of our settled derivative loss of $0.3 million for the quarter ended September 30, 2008, decreased 45% to $66.25 per barrel from $120.09 per barrel in the same period in 2008.  The increase in natural gas production volume was due primarily to new production contributions from Barnett Shale development.

-20-

 
The following table summarizes production volumes, average sales prices (excluding the impact of derivatives) and operating revenues for the three months ended September 30, 2009 and 2008:

               
2009 Period
 
   
Three Months Ended
   
Compared to 2008 Period
 
   
September 30,
   
Increase
   
% Increase
 
   
2009
   
2008
   
(Decrease)
   
(Decrease)
 
Production volumes
                       
Oil and condensate (MBbls)
    44       43       1       1 %
Natural gas (MMcf)
    7,947       5,724       2,223       39 %
Average sales prices
                               
Oil and condensate (per Bbl)
  $ 66.25     $ 120.09     $ (53.84 )     (45 )%
Natural gas (per Mcf)
    2.60       8.78       (6.18 )     (70 )%
Operating revenues (In thousands)
                         
Oil and condensate
  $ 2,886     $ 5,194     $ (2,308 )     (44 )%
Natural gas
    20,698       50,233       (29,535 )     (59 )%
Other(1)
    263       3,100       (2,837 )     (92 )%
                                 
Total Operating Revenues
  $ 23,847     $ 58,527     $ (34,680 )     (59 )%
                                 
__________
(1)  
Includes gathering income and third party gas sales that is also included as third-party purchases in operating expense.

Oil and natural gas operating expenses for the three months ended September 30, 2009 decreased 50% to $5.2 million from $10.4 million for the same period in 2008, primarily as a result of decreased transportation and other product costs of $2.9 million mainly attributable to a change in pricing and transportation contractual arrangements, a $1.3 million decrease in severance taxes associated with decreased revenues and a decrease of $1.0 million due to a general decline in oil field services.

Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2009 decreased 10% to $12.5 million ($1.53 per Mcfe) from $13.9 million ($2.33 per Mcfe) for the same period in 2008.  This decrease in DD&A was primarily due to a lower depletion rate resulting from impairment charges that reduced the depletable full-cost pool in the fourth quarter of 2008 and the first quarter of 2009, partially offset by increased production.

General and administrative expense increased to $7.6 million for the three months ended September 30, 2009 from $5.8 million for the corresponding period in 2008.  The increase was due primarily to an increase in non-cash, stock-based compensation of $1.2 million as a result of additional compensation awards.  In addition, during the third quarter of 2009, we made the first $100,000 cash payment of a $1.0 million pledge to establish a Carrizo Oil & Gas, Inc. endowed scholarship fund at the University of Texas at Arlington (“UTA”), a university which is located within the area of our significant operations in the Barnett Shale.  We have the option to pay the remaining portion of this pledge in shares of our common stock.

The net loss on derivatives of $2.0 million in the third quarter of 2009 was comprised of $20.7 million of unrealized mark-to-market loss on derivatives and $18.7 million of realized gain on net settled oil and natural gas derivatives.  The net gain on derivatives of $77.7 million in the third quarter of 2008 was comprised of a $76.4 million net unrealized mark-to-market gain on derivatives and a $1.3 million realized gain on cash-settled derivatives.

Interest expense and capitalized interest for the three months ended September 30, 2009 were $9.9 million and $5.0 million, respectively, as compared to $8.5 million and $6.3 million for the same period in 2008 primarily attributable to an increase of approximately $2.0 million in cash interest expense associated with higher debt levels on the Senior Credit Facility.

Nine Months Ended September 30, 2009,
Compared to the Nine Months Ended September 30, 2008

Revenues from oil and natural gas production for the nine months ended September 30, 2009 decreased 54% to $80.2 million from $173.7 million for the same period in 2008 due to declining oil and natural gas prices.  Production volumes for natural gas for the nine months ended September 30, 2009 increased 34% to 23.6 Bcf from 17.6 Bcf for the same period in 2008.  Average natural gas prices,
 
-21-

 
excluding the impact of our settled derivatives gain of $61.5 million and loss of $7.9 million for the nine months ended September 30, 2009 and 2008, respectively, decreased to $3.10 per Mcf for the nine months ended September 30, 2009 from $8.98 per Mcf in the same period in 2008.  Average oil prices, excluding the impact of our settled derivative gain of $2.8 million and loss of $1.1 million for the nine months ended September 30, 2009 and 2008, respectively, decreased 52% to $54.08 per barrel from $112.19 per barrel in the same period in 2008.  The increase in natural gas production volume was due primarily to new production in the Barnett Shale development.

The following table summarizes production volumes, average sales prices (excluding the impact of derivatives) and operating revenues for the nine months ended September 30, 2009 and 2008:

               
2009 Period
 
   
Nine Months Ended
   
Compared to 2008 Period
 
   
September 30,
   
Increase
   
% Increase
 
   
2009
   
2008
   
(Decrease)
   
(Decrease)
 
Production volumes
                       
Oil and condensate (MBbls)
    129       144       (15 )     11 %
Natural gas (MMcf)
    23,589       17,555       6,033       34 %
Average sales prices
                               
Oil and condensate (per Bbl)
  $ 54.08     $ 112.19     $ (58.11 )     (52 )%
Natural gas (per Mcf)
    3.10       8.98       (5.88 )     (65 )%
Operating revenues (In thousands)
                         
Oil and condensate
  $ 6,952     $ 16,131     $ (9,179 )     (57 )%
Natural gas
    73,235       157,564       (84,329 )     (54 )%
Other(1)
    1,034       5,780       (4,746 )     (82 )%
                                 
Total Operating Revenues
  $ 81,221     $ 179,475     $ (98,254 )     (55 )%
                                 
__________
(1)  
Includes gathering income and third party gas sales that is also included as third-party purchases in operating expense.

Oil and natural gas operating expense for the nine months ended September 30, 2009 decreased 19% to $22.8 million from $28.0 million for the same period in 2008, primarily as a result of decreased severance tax expense of $5.1 million associated with refunds from certain wells that qualified for a tight-gas sands tax credit for prior production periods and decreased revenues and increased workover expenses of $0.4 million, partially offset by $0.8 million in decreased transportation costs mainly attributable to a change in the pricing and transportation contractual arrangements beginning in the third quarter of 2009.

Depreciation, depletion and amortization (DD&A) expense for the nine months ended September 30, 2009 decreased 4% to $40.0 million ($1.64 per Mcfe) from $41.9 million ($2.27 per Mcfe) for the same period in 2008.  This decrease in DD&A was primarily due to impairment charges in the fourth quarter of 2008 and the first quarter of 2009 that reduced the depletable full-cost pool, partially offset by increased production.

The significant decline in oil and natural gas prices since December 31, 2008, indicated by average posted prices of $3.17 per Mcf for natural gas and $51.76 per Bbl for oil on May 6, 2009, caused the discounted present value (discounted at ten percent) of future net cash flows from our proved oil and gas reserves to fall below our net book basis in the proved oil and gas properties at March 31, 2009.  This resulted in a non-cash, ceiling test write-down of $216.4 million ($138.0 million after tax).

General and administrative expense for the nine months ended September 30, 2009 increased by $4.0 million to $21.9 million from $17.9 million for the corresponding period in 2008 primarily as a result of an increase in non-cash, stock-based compensation of $4.0 million as a result of additional deferred compensation awards.  In addition, we made the first $100,000 cash payment of a $1.0 million pledge to establish a Carrizo Oil & Gas, Inc. endowed scholarship fund at UTA, a university which is located within the area of our significant operations in the Barnett Shale.

The net gain on derivatives of $25.8 million in the first nine months of 2009 was comprised of a $64.3 million realized gain on cash-settled oil and natural gas derivatives and a $38.5 million of net unrealized mark-to-market loss on derivatives.  The net loss on derivatives of $0.4 million in the first nine months of 2008 was comprised of $10.2 million of realized loss on net settled derivatives,
 
-22-

 
$13.1 million of net unrealized mark-to-market gain on derivatives and $3.3 million of realized loss on interest rate derivatives associated with the early termination of the interest rate swaps.

In May 2008, we repaid our outstanding borrowings under the Second Lien Facility and terminated the facility. As a result, we recorded a $5.7 million loss associated with the early extinguishment of debt consisting of a $4.6 million non-cash write-off of deferred loan costs and $1.1 million in penalties paid for early retirement.

Interest expense and capitalized interest for the nine months ended September 30, 2009 were $28.6 million and $15.1 million, respectively, as compared to $21.0 million and $14.5 million for the same period in 2008 primarily attributable to an increase of approximately $5.1 million in non-cash interest expense associated with the amortization of the debt discount on the Senior Convertible Notes and higher debt levels on the Senior Credit Facility.

Liquidity and Capital Resources