NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.
Nature of Operations
Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of oil and gas primarily from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, the Barnett Shale in North Texas, and the Utica Shale in Ohio.
2.
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of the Company after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. The consolidated financial statements reflect all necessary adjustments, all of which were of a normal recurring nature and are in the opinion of management necessary for a fair presentation of the Company’s interim financial position, results of operations and cash flows. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The operating results for the
three and six months ended June 30,
2013
are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2012
.
Reclassifications
Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total shareholders’ equity, net income, or net cash provided by or used in operating, investing or financing activities.
Discontinued Operations
On December 27, 2012, the Company agreed to sell Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, where Carrizo UK owned a
15%
non-operated working interest and certain overriding royalty interests. The sale closed on February 22, 2013. Accordingly, the Company classified the U.K. North Sea assets and associated liabilities as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets as of December 31, 2012. Beginning March 31, 2013, the Company classified the remaining assets and liabilities associated with the U.K. North Sea as assets of discontinued operations and liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net of income taxes, in the consolidated statements of income, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to assets held for sale and discontinued operations is included in “Note
3.
Discontinued Operations” and “Note
10.
Condensed Consolidating Financial Information.”
Use of Estimates
The preparation of financial statements in conformity with GAAP 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 financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.
Significant estimates include volumes of proved oil and gas reserves, which are used in calculating the amortization of proved oil and gas property costs, the present value of future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the timing of asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title, drilling requirements and royalty obligations. These estimates also depend on assumptions regarding quantities and
production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in our estimates. Other significant estimates include impairments of unproved properties, fair values of derivative instruments, stock-based compensation, collectability of receivables, disputed claims, interpretation of contractual arrangements (including royalty obligations and notional interest calculations) and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling, testing and production as well as subsequent changes in oil and gas prices, counterparty creditworthiness, interest rates and the market value and volatility of the Company's common stock.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with original maturities of three months or less.
Accounts Receivable and Allowance for Doubtful Accounts
The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. At
June 30, 2013
and
December 31, 2012
, the Company’s allowance for doubtful accounts was
$0.7 million
and
$1.4 million
, respectively.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third-party working interest owners in the oil and gas industry or development advances to third-party operators for drilling and completion costs of wells in progress. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.
Derivative instruments subject the Company to a concentration of credit risk. See “Note
8.
Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.
Oil and Gas Properties
Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs, including payroll and stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled
$4.2 million
and
$4.1 million
for the
three months ended June 30,
2013
and
2012
, respectively, and
$6.3 million
and
$7.5 million
for the
six months ended June 30,
2013
and
2012
, respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred.
Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average depreciation, depletion and amortization (“DD&A”) per Boe was
$19.65
and
$18.13
for the
three months ended June 30,
2013
and
2012
, respectively, and
$19.36
and
$15.93
for the
six months ended June 30,
2013
and
2012
, respectively.
Unproved properties, which are not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Significant costs of unevaluated properties and exploratory wells in progress are assessed individually on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs are added to the oil and gas property costs subject to amortization. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved leasehold within the next
five
years and exploratory wells in progress within the next year. Individually insignificant costs of unevaluated properties are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease term of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs and exploratory wells in progress of
$7.5 million
and
$6.0 million
for the
three months ended June 30,
2013
and
2012
, respectively, and
$14.3 million
and
$12.0 million
for the
six months ended June 30,
2013
and
2012
, respectively. Interest is capitalized on the average
balance of unevaluated leasehold and seismic costs and the average balance of exploratory wells in progress using a weighted-average interest rate based on outstanding borrowings.
Proceeds from the sale of oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. On February 22, 2013, the Company closed on the sale of Carrizo UK, which included all of the Company's proved reserves in its U.K. cost center. As a result, in the first quarter of 2013, the Company recognized a
$37.3 million
gain in “net income from discontinued operations, net of income taxes” in the consolidated statements of income. Other than the sale of Carrizo UK noted above, the Company has not had any sales of oil and gas properties that significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through
June 30, 2013
.
Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of
10%
, (B) the costs of properties not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.
The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment.
Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from
five
to
ten
years.
Deferred Financing Costs
Deferred financing costs include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of the debt securities and costs associated with revolving credit facilities. The capitalized costs are amortized to interest expense, net of amounts capitalized using the effective interest method over the terms of the debt securities or credit facilities.
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company's derivative instruments are based on a third-party pricing model that uses market data obtained from third-party sources, including (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as the borrowings bear interest at variable rates of interest. The carrying amounts of the Company’s senior notes and convertible senior notes may not approximate fair value because the notes bear interest at fixed rates of interest. See “Note
6.
Long-Term Debt” and “Note
9.
Fair Value Measurements.”
Asset Retirement Obligations
The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized as a liability at its fair value when the well is drilled with an associated increase in oil and gas property costs. Asset retirement obligations require estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligations are discounted using a credit-adjusted risk-free interest rate which is accreted over the estimated productive lives of the oil and gas properties to their expected settlement values. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in estimated costs to plug and abandon wells and changes in estimated timing of oil and gas property retirement. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement, which is included in oil and gas property costs. On an interim basis, the Company reassesses
the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.
Commitments and Contingencies
Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable.
Revenue Recognition
Oil and gas revenues are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting for oil and gas revenues whereby revenue is recognized for all oil and gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as an asset or liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of
June 30, 2013
and
December 31, 2012
, the Company did not have any material production imbalances.
Derivative Instruments
The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their balance sheet date fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with a portion of its forecasted oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of income. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of income. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.
The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including 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 with 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. See “Note
8.
Derivative Instruments” for further discussion of the Company’s derivative instruments.
Stock-Based Compensation
The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option of the Company, SARs that may only be settled in cash, restricted stock awards and units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expense for the periods indicated which is reflected as general and administrative expense in the consolidated statements of income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In thousands)
|
Stock Appreciation Rights
|
|
$
|
7
|
|
|
$
|
(2,975
|
)
|
|
$
|
3,939
|
|
|
$
|
(1,309
|
)
|
Restricted Stock Awards and Units
|
|
4,462
|
|
|
5,476
|
|
|
8,319
|
|
|
8,581
|
|
|
|
4,469
|
|
|
2,501
|
|
|
12,258
|
|
|
7,272
|
|
Less: amounts capitalized
|
|
(1,486
|
)
|
|
(985
|
)
|
|
(2,792
|
)
|
|
(1,740
|
)
|
Total Stock-Based Compensation Expense
|
|
$
|
2,983
|
|
|
$
|
1,516
|
|
|
$
|
9,466
|
|
|
$
|
5,532
|
|
Income Tax Benefit
|
|
$
|
(1,107
|
)
|
|
$
|
(562
|
)
|
|
$
|
(3,470
|
)
|
|
$
|
(2,052
|
)
|
Stock Options and SARs.
For stock options and SARs that the Company expects to settle in common stock, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally
three
years). For SARs that the Company expects to settle in cash, stock-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally
three
years) and classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as other long-term liabilities. Subsequent to vesting, the liability for SARs that the Company expects to settle in cash is remeasured in earnings at
each reporting period based on fair value until the awards are settled. The Company recognizes stock-based compensation expense over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire
ten
years after the date of grant. SARs typically expire between
four
and
seven
years after the date of grant. The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs.
Restricted Stock Awards and Units
. For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally
one
to
three
years) using the straight-line method, except for award or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the price of the Company’s common stock on the grant date. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally
three
years) using the straight-line method.
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 its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments by taxing jurisdiction. 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, the deferred tax assets are reduced by a valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense.
Net Income From Continuing Operations Per Common Share
Supplemental net income from continuing operations per common share information is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In thousands, except per share amounts)
|
Net income from continuing operations
|
|
$
|
35,837
|
|
|
$
|
25,683
|
|
|
$
|
38,361
|
|
|
$
|
36,359
|
|
Basic weighted average common shares outstanding
|
|
40,078
|
|
|
39,596
|
|
|
39,928
|
|
|
39,520
|
|
Effect of dilutive instruments
|
|
532
|
|
|
446
|
|
|
541
|
|
|
467
|
|
Diluted weighted average common shares outstanding
|
|
40,610
|
|
|
40,042
|
|
|
40,469
|
|
|
39,987
|
|
Net income from continuing operations per common share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.89
|
|
|
$
|
0.65
|
|
|
$
|
0.96
|
|
|
$
|
0.92
|
|
Diluted
|
|
$
|
0.88
|
|
|
$
|
0.64
|
|
|
$
|
0.95
|
|
|
$
|
0.91
|
|
Basic net income from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, stock options, SARs expected to be settled in common stock, warrants and convertible debt. The Company excludes shares related to restricted stock awards, units and stock options from the calculation of diluted weighted average shares outstanding when the grant date prices are greater than the average market prices of the common shares for the period as the effect would be antidilutive to the computation. The shares excluded for the periods ending
June 30, 2013
and
2012
were not significant. Shares of common stock subject to issuance upon the conversion of the Company's convertible senior notes did not have an effect on the calculation of dilutive shares for the
three and six months ended June 30,
2013
or
2012
, because the conversion price was in excess of the market price of the common stock for those periods.
Recently Adopted Accounting Pronouncements
Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11,
Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities
, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity's financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. We adopted this new disclosure requirement effective January 1, 2013. The adoption did not have a material effect on our consolidated financial statements.
3.
Discontinued Operations
On February 22, 2013, the Company closed on the sale of Carrizo UK, and all of its interest in the Huntington Field discovery, including a
15%
non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of
$184.0 million
, including the assumption and repayment by Iona Energy of the
$55.0
million of borrowings outstanding under Carrizo UK's senior secured multicurrency credit facility as of the closing date.
The assets of discontinued operations of
$6.9 million
primarily relate to the remaining deferred consideration which the Company expects to receive during 2013. The liabilities of discontinued operations of
$27.9 million
relate to an accrual for estimated future obligations related to the sale. See “Note
2.
Summary of Significant Accounting Policies—Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts of assets and liabilities related to the sale of Carrizo UK.
The following table summarizes the amounts included in net income from discontinued operations, net of income taxes presented in the consolidated statements of income for the
three and six months ended June 30,
2013
and
2012
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In thousands)
|
OIL AND GAS REVENUES
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
General and administrative
|
|
296
|
|
|
9
|
|
|
301
|
|
|
12
|
|
Accretion related to asset retirement obligations
|
|
—
|
|
|
78
|
|
|
36
|
|
|
154
|
|
TOTAL COST AND EXPENSES
|
|
296
|
|
|
87
|
|
|
337
|
|
|
166
|
|
OPERATING LOSS
|
|
(296
|
)
|
|
(87
|
)
|
|
(337
|
)
|
|
(166
|
)
|
OTHER INCOME AND EXPENSES
|
|
|
|
|
|
|
|
|
Gain on sale of discontinued operations
|
|
—
|
|
|
—
|
|
|
37,294
|
|
|
—
|
|
Decrease in estimated future obligations
|
|
2,565
|
|
|
—
|
|
|
2,565
|
|
|
—
|
|
Gain (loss) on derivative instruments, net
|
|
(31
|
)
|
|
357
|
|
|
(75
|
)
|
|
(408
|
)
|
Interest expense
|
|
—
|
|
|
(919
|
)
|
|
(253
|
)
|
|
(1,798
|
)
|
Capitalized interest
|
|
—
|
|
|
1,798
|
|
|
253
|
|
|
1,798
|
|
Other income (expense), net
|
|
308
|
|
|
203
|
|
|
332
|
|
|
(594
|
)
|
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES
|
|
2,546
|
|
|
1,352
|
|
|
39,779
|
|
|
(1,168
|
)
|
INCOME TAX (EXPENSE) BENEFIT
|
|
(1,414
|
)
|
|
1,469
|
|
|
(14,989
|
)
|
|
2,736
|
|
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES
|
|
$
|
1,132
|
|
|
$
|
2,821
|
|
|
$
|
24,790
|
|
|
$
|
1,568
|
|
Income Taxes
Carrizo UK is a disregarded entity for U.S. income tax purposes. Accordingly, the income tax (expense) benefit reflected above includes the Company’s U.S. deferred income tax (expense) benefit associated with the income (loss) from discontinued operations before income taxes. The related U.S. deferred tax assets and liabilities have been classified as deferred income taxes of continuing operations in the consolidated balance sheet.
Foreign Currency
The U.S. dollar was the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occurred due to the realization of assets and the settlement of liabilities denominated in a currency other than the functional currency were recorded as Other income (expense), net.
4.
Property and Equipment, Net
At
June 30, 2013
and
December 31, 2012
, property and equipment, net consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2013
|
|
December 31,
2012
|
|
|
(In thousands)
|
Proved oil and gas properties
|
|
$
|
2,086,461
|
|
|
$
|
1,713,827
|
|
Accumulated depreciation, depletion and amortization
|
|
(656,660
|
)
|
|
(561,279
|
)
|
Proved oil and gas properties, net
|
|
1,429,801
|
|
|
1,152,548
|
|
Unproved properties, not being amortized
|
|
|
|
|
Unevaluated leasehold costs
|
|
284,362
|
|
|
238,833
|
|
Exploratory wells in progress
|
|
30,936
|
|
|
43,803
|
|
Capitalized interest
|
|
45,236
|
|
|
41,052
|
|
Total unproved properties, not being amortized
|
|
360,534
|
|
|
323,688
|
|
Other property and equipment
|
|
18,975
|
|
|
17,079
|
|
Accumulated depreciation
|
|
(6,448
|
)
|
|
(5,641
|
)
|
Other property and equipment, net
|
|
12,527
|
|
|
11,438
|
|
Total property and equipment, net
|
|
$
|
1,802,862
|
|
|
$
|
1,487,674
|
|
Utica Shale Joint Venture
. On
January 15, 2013
, we exercised our option for an additional
40%
in the remaining properties held through our joint venture with ACP II Marcellus LLC (“ACP II”), which is also one of our joint venture partners in the Marcellus Shale, and ACP III Utica LLC (“ACP III”), both affiliates of Avista Capital Holdings, LP, a private equity firm (collectively with ACP II and ACP III, “Avista”) by paying
$63.1 million
. Following the option exercise, the Company has elected to acquire additional properties on a
50
/
50
basis with Avista. The Company's right to receive distributions associated with the properties owned by ACP III through its B Units in ACP III terminated upon the consummation of the Company’s January 15, 2013 option to increase its interest in the Avista Utica joint venture properties.
5.
Income Taxes
The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. Income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate income tax rate of
35%
to income from continuing operations before income taxes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In thousands)
|
Income tax expense at the statutory rate
|
|
$
|
20,427
|
|
|
$
|
14,687
|
|
|
$
|
21,824
|
|
|
$
|
20,273
|
|
State income taxes, net of U.S. federal income tax benefit
|
|
2,049
|
|
|
843
|
|
|
2,063
|
|
|
1,087
|
|
Other, net
|
|
69
|
|
|
749
|
|
|
107
|
|
|
204
|
|
Income tax expense
|
|
$
|
22,545
|
|
|
$
|
16,279
|
|
|
$
|
23,994
|
|
|
$
|
21,564
|
|
As of
June 30, 2013
, the Company had U.S. income tax loss carryforwards of approximately
$179.6 million
. The U.S. loss carryforwards expire between
2019
and
2032
if not utilized in earlier periods. The realization of the deferred tax assets related to the U.S. loss carryforwards is dependent on the Company’s ability to generate sufficient future taxable income, which the Company
expects to be able to generate within the applicable carryforward periods. Accordingly, the Company believes that it is more likely than not that its deferred tax assets related to the U.S. loss carryforwards will be fully realized.
At
June 30, 2013
, 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. Long-Term Debt
Long-term debt consisted of the following at
June 30, 2013
and
December 31, 2012
:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2013
|
|
December 31,
2012
|
|
|
(In thousands)
|
8.625% Senior Notes
|
|
$
|
600,000
|
|
|
$
|
600,000
|
|
Unamortized discount for 8.625% Senior Notes
|
|
(4,521
|
)
|
|
(4,849
|
)
|
7.50% Senior Notes
|
|
300,000
|
|
|
300,000
|
|
4.375% Convertible Senior Notes
|
|
4,425
|
|
|
73,750
|
|
Unamortized discount for 4.375% Convertible Senior Notes
|
|
—
|
|
|
(1,093
|
)
|
Senior Secured Revolving Credit Facility
|
|
28,000
|
|
|
—
|
|
|
|
$
|
927,904
|
|
|
$
|
967,808
|
|
Convertible Senior Notes
On June 3, 2013, the Company completed a required tender offer to repurchase the
4.375%
convertible senior notes due 2028, at par plus accrued but unpaid interest to but excluding June 1, 2013, for aggregate consideration of
$69.3 million
(approximately
94%
of the convertible senior notes outstanding prior to the tender offer). Each holder received
$1,000
for each
$1,000
principal amount of convertible senior notes repurchased in the tender offer. Due to the Company repurchasing the convertible senior notes on June 1, 2013, which is the date the semi-annual interest payment was due and after the record date, the Company paid only the regular interest payment as there was no accrued or unpaid interest due as part of the repurchase price. As of June 30, 2013,
$4.4 million
aggregate principal amount of convertible senior notes remained outstanding. The holders of our remaining
$4.4 million
aggregate principal amount of convertible senior notes may require us to repurchase the remaining notes on June 1, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to
100%
of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. We may also redeem notes at any time at a redemption price equal to
100%
of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.
Senior Secured Revolving Credit Facility
The Company is party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the administrative agent. The revolving credit facility provides for a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the senior credit agreement governing the revolving credit facility) and (ii)
$750.0 million
. The revolving credit facility matures on
January 27, 2016
. The revolving credit facility is secured by substantially all of the Company’s U.S. assets and is guaranteed by all of the Company’s existing subsidiaries (other than Monument Exploration LLC, Carrizo UK Bardolph Ltd, and Carrizo (Permian) LLC).
As a result of the Spring 2013 borrowing base redetermination, effective April 29, 2013, the borrowing base was increased to
$530.0 million
from
$365.0 million
after considering the addition of proved reserves as a result of the Company’s successful ongoing drilling program. The borrowing base will be redetermined by the lenders at least semi-annually, generally on each May 1 and November 1, with the next redetermination expected in the Fall of 2013. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement governing the revolving credit facility.
The Company is subject to certain covenants under the terms of the revolving credit facility which include the maintenance of the following financial covenants: (1) a ratio of Total Debt to EBITDA of not more than
4.00
to
1.00
; (2) a Current Ratio of not less than
1.00
to
1.00
; (3) a ratio of Senior Debt to EBITDA of not more than
2.50
to
1.00
; and (4) a ratio of EBITDA to Interest Expense of not less than
2.50
to
1.00
(each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). At
June 30, 2013
, the ratio of Total Debt to EBITDA was
2.50
to
1.00
, the Current Ratio was
1.83
to
1.00
, the ratio of Senior Debt to EBITDA was
0.07
to
1.00
and the ratio of EBITDA to Interest Expense was
5.31
to
1.00
. Total Debt and Senior Debt, as defined in the credit agreement governing the revolving credit facility, are net of cash and cash equivalents of the Company. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the revolving credit facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.
At
June 30, 2013
, the Company had
$28.0 million
of borrowings outstanding under the revolving credit facility with a weighted average interest rate of
2.19%
. At
June 30, 2013
, the Company also had
$0.9 million
in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Future availability under the
$530.0 million
borrowing base is subject to
the terms and covenants of the revolving credit facility. The revolving credit facility is generally used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.
7.
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 expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
The results of 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.
8.
Derivative Instruments
The Company uses various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure plan. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company’s current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to
60
months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of income for the period in which the changes occur.
The fair value of derivative instruments at
June 30, 2013
and
December 31, 2012
was a net asset of
$32.3 million
and
$29.2 million
, respectively. The following sets forth a summary of the distribution of net fair value of the Company’s derivative instruments:
|
|
|
|
|
|
|
|
Counterparty
|
|
June 30, 2013
|
|
December 31, 2012
|
Credit Suisse
|
|
38
|
%
|
|
40
|
%
|
Societe Generale
|
|
35
|
%
|
|
22
|
%
|
Wells Fargo
|
|
13
|
%
|
|
2
|
%
|
BNP Paribas
|
|
13
|
%
|
|
33
|
%
|
BBVA Compass
|
|
1
|
%
|
|
3
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
Master netting agreements are in place with each of these counterparties. Because the counterparties are investment grade financial institutions, the Company believes it has minimal credit risk and accordingly does not currently require its counterparties to post collateral to support the asset positions of its derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the financial viability of its counterparties. Because Credit Suisse, BBVA Compass, Wells Fargo, and Societe Generale are lenders in the Company’s revolving credit facility, the Company is not required to post collateral with respect to derivative instruments in a net liability position with these counterparties as the contracts are secured by the revolving credit facility. BNP Paribas may require the Company to post collateral with respect to derivative instruments in a net liability position. The Company had no derivative instruments in a net liability position with any counterparty at
June 30, 2013
and
December 31, 2012
.
The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of
June 30, 2013
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes
(in MMBtu)
|
|
Weighted
Average
Floor Price
($/MMBtu)
|
|
Weighted
Average
Ceiling Price
($/MMBtu)
|
2013
|
|
10,120,000
|
|
|
$
|
4.58
|
|
|
$
|
4.58
|
|
2014
|
|
18,250,000
|
|
|
$
|
4.07
|
|
|
$
|
4.36
|
|
2015
|
|
3,650,000
|
|
|
$
|
4.33
|
|
|
$
|
4.33
|
|
The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of
June 30, 2013
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes
(in Bbls)
|
|
Weighted
Average
Floor Price
($/Bbl)
|
|
Weighted
Average
Ceiling Price
($/Bbl)
|
2013
|
|
1,766,400
|
|
|
$
|
90.17
|
|
|
$
|
100.87
|
|
2014
|
|
3,375,500
|
|
|
$
|
90.59
|
|
|
$
|
96.99
|
|
2015
|
|
1,806,750
|
|
|
$
|
89.41
|
|
|
$
|
94.96
|
|
2016
|
|
244,000
|
|
|
$
|
85.00
|
|
|
$
|
104.00
|
|
In connection with the crude oil derivative instruments above, the Company has entered into protective put spreads. For example, during
2014
, at market prices below the short put price of
$65.00
, the floor price becomes the market price plus the put spread of
$20.00
on
182,500
of the
3,375,500
Bbls and the remaining
3,193,000
Bbls would have a floor price of
$90.59
.
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes
(in Bbls)
|
|
Weighted
Average
Short Put Price
($/Bbl)
|
|
Weighted
Average
Put Spread
($/Bbl)
|
2014
|
|
182,500
|
|
|
$
|
65.00
|
|
|
$
|
20.00
|
|
2015
|
|
365,000
|
|
|
$
|
65.00
|
|
|
$
|
20.00
|
|
2016
|
|
244,000
|
|
|
$
|
65.00
|
|
|
$
|
20.00
|
|
For the
three and six months ended June 30,
2013
and
2012
, the Company recorded the following related to its oil and gas derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In thousands)
|
Realized gain (loss) on derivative instruments, net
|
|
$
|
2,291
|
|
|
$
|
9,962
|
|
|
$
|
8,006
|
|
|
$
|
21,095
|
|
Unrealized gain (loss) on derivative instruments, net
|
|
23,435
|
|
|
27,928
|
|
|
3,166
|
|
|
20,598
|
|
Gain (loss) on derivative instruments, net
|
|
$
|
25,726
|
|
|
$
|
37,890
|
|
|
$
|
11,172
|
|
|
$
|
41,693
|
|
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.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of
June 30, 2013
and
December 31, 2012
. All items included in the tables below are Level 2 inputs within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2013
|
Description
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
37,768
|
|
|
$
|
(5,442
|
)
|
|
$
|
32,326
|
|
Liabilities:
|
|
|
|
|
|
|
Derivative instruments
|
|
(5,442
|
)
|
|
5,442
|
|
|
—
|
|
Total
|
|
$
|
32,326
|
|
|
$
|
—
|
|
|
$
|
32,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
Description
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
36,452
|
|
|
$
|
(7,291
|
)
|
|
$
|
29,161
|
|
Liabilities:
|
|
|
|
|
|
|
Derivative instruments
|
|
(7,291
|
)
|
|
7,291
|
|
|
—
|
|
Total
|
|
$
|
29,161
|
|
|
$
|
—
|
|
|
$
|
29,161
|
|
The fair values of the Company’s derivative instruments are based on a third-party pricing model that uses market data obtained from third-party sources, including (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The estimates of fair value are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.
The fair values reported in the consolidated balance sheets are as of a particular point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The Company had
no
transfers in or out of Levels 1 or 2 for the
six months ended June 30,
2013
or
2012
.
Fair Value of Other Financial Instruments
The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and long-term debt which are classified as Level 1 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The following table presents the carrying amounts and fair values of the Company’s senior notes and convertible senior notes, based on quoted market prices, as of
June 30, 2013
and
December 31, 2012
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2013
|
|
December 31, 2012
|
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
|
(In thousands)
|
8.625% Senior Notes
|
|
$
|
595,479
|
|
|
$
|
640,140
|
|
|
$
|
595,151
|
|
|
$
|
645,000
|
|
7.50% Senior Notes
|
|
300,000
|
|
|
312,000
|
|
|
300,000
|
|
|
308,250
|
|
4.375% Convertible Senior Notes
|
|
4,425
|
|
|
4,436
|
|
|
72,657
|
|
|
73,842
|
|
10.
Condensed Consolidating Financial Information
In November 2010 and November 2011, the Company and certain of the Company’s wholly-owned subsidiaries issued in private placements
$400.0 million
and
$200.0 million
, respectively, aggregate principal amount of the Company’s 8.625% Senior Notes. Certain, but not all, of the Company’s wholly-owned subsidiaries have issued full, unconditional and joint and several guarantees of the 8.625% Senior Notes and may guarantee future issuances of debt securities. In June 2011 and February 2012, the Company completed the exchange of registered
8.625%
Senior Notes for any and all of its unregistered
$400.0 million
and
$200.0 million
aggregate principal amount of
8.625%
Senior Notes, respectively. In September 2012, the Company and certain of the Company’s wholly-owned subsidiaries issued in a public offering,
$300.0 million
aggregate principal amount of the Company’s
7.50%
Senior Notes.
The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is
100%
owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of
June 30, 2013
and
December 31, 2012
, and for the
three and six months ended June 30,
2013
and
2012
on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.
Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A.
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2013
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
1,779,723
|
|
|
$
|
153,382
|
|
|
$
|
—
|
|
|
$
|
(1,780,037
|
)
|
|
$
|
153,068
|
|
Assets of discontinued operations
|
|
6,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,875
|
|
Property and equipment, net
|
|
469
|
|
|
1,780,872
|
|
|
—
|
|
|
21,521
|
|
|
1,802,862
|
|
Investments in subsidiaries
|
|
20,539
|
|
|
—
|
|
|
—
|
|
|
(20,539
|
)
|
|
—
|
|
Other assets
|
|
52,108
|
|
|
—
|
|
|
—
|
|
|
(4,616
|
)
|
|
47,492
|
|
Total assets
|
|
$
|
1,859,714
|
|
|
$
|
1,934,254
|
|
|
$
|
—
|
|
|
$
|
(1,783,671
|
)
|
|
$
|
2,010,297
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
250,191
|
|
|
$
|
1,890,213
|
|
|
$
|
—
|
|
|
$
|
(1,780,037
|
)
|
|
$
|
360,367
|
|
Current liabilities of discontinued operations
|
|
9,936
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,936
|
|
Long-term liabilities
|
|
933,960
|
|
|
23,502
|
|
|
—
|
|
|
6,281
|
|
|
963,743
|
|
Long-term liabilities of discontinued operations
|
|
17,999
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,999
|
|
Shareholders’ equity (deficit)
|
|
647,628
|
|
|
20,539
|
|
|
—
|
|
|
(9,915
|
)
|
|
658,252
|
|
Total liabilities and shareholders’ equity
|
|
$
|
1,859,714
|
|
|
$
|
1,934,254
|
|
|
$
|
—
|
|
|
$
|
(1,783,671
|
)
|
|
$
|
2,010,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
1,689,430
|
|
|
$
|
130,487
|
|
|
$
|
—
|
|
|
$
|
(1,613,094
|
)
|
|
$
|
206,823
|
|
Current assets held for sale
|
|
—
|
|
|
—
|
|
|
1,882
|
|
|
—
|
|
|
1,882
|
|
Property and equipment, net
|
|
23,041
|
|
|
1,443,064
|
|
|
—
|
|
|
21,569
|
|
|
1,487,674
|
|
Investments in subsidiaries
|
|
14,588
|
|
|
—
|
|
|
—
|
|
|
(14,588
|
)
|
|
—
|
|
Long-term assets held for sale
|
|
12,670
|
|
|
—
|
|
|
119,956
|
|
|
—
|
|
|
132,626
|
|
Other assets
|
|
46,913
|
|
|
16,928
|
|
|
—
|
|
|
(8,850
|
)
|
|
54,991
|
|
Total assets
|
|
$
|
1,786,642
|
|
|
$
|
1,590,479
|
|
|
$
|
121,838
|
|
|
$
|
(1,614,963
|
)
|
|
$
|
1,883,996
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
179,221
|
|
|
$
|
1,631,887
|
|
|
$
|
—
|
|
|
$
|
(1,560,853
|
)
|
|
$
|
250,255
|
|
Current liabilities associated with assets held for sale
|
|
9,880
|
|
|
—
|
|
|
38,783
|
|
|
—
|
|
|
48,663
|
|
Long-term liabilities
|
|
973,003
|
|
|
3,512
|
|
|
—
|
|
|
—
|
|
|
976,515
|
|
Long-term liabilities associated with assets held for sale
|
|
—
|
|
|
—
|
|
|
23,547
|
|
|
—
|
|
|
23,547
|
|
Shareholders’ equity (deficit)
|
|
624,538
|
|
|
(44,920
|
)
|
|
59,508
|
|
|
(54,110
|
)
|
|
585,016
|
|
Total liabilities and shareholders’ equity
|
|
$
|
1,786,642
|
|
|
$
|
1,590,479
|
|
|
$
|
121,838
|
|
|
$
|
(1,614,963
|
)
|
|
$
|
1,883,996
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2013
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Oil and gas revenues
|
|
$
|
2,086
|
|
|
$
|
132,138
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
134,224
|
|
Cost and expenses
|
|
19,315
|
|
|
68,474
|
|
|
—
|
|
|
(183
|
)
|
|
87,606
|
|
Operating income (loss)
|
|
(17,229
|
)
|
|
63,664
|
|
|
—
|
|
|
183
|
|
|
46,618
|
|
Other income (expense), net
|
|
17,544
|
|
|
(5,780
|
)
|
|
—
|
|
|
—
|
|
|
11,764
|
|
Income (loss) from continuing operations before income taxes
|
|
315
|
|
|
57,884
|
|
|
—
|
|
|
183
|
|
|
58,382
|
|
Income tax (expense) benefit
|
|
(110
|
)
|
|
(20,365
|
)
|
|
—
|
|
|
(2,070
|
)
|
|
(22,545
|
)
|
Equity in income (loss) of subsidiaries
|
|
37,519
|
|
|
—
|
|
|
—
|
|
|
(37,519
|
)
|
|
—
|
|
Net income (loss) from continuing operations
|
|
37,724
|
|
|
37,519
|
|
|
—
|
|
|
(39,406
|
)
|
|
35,837
|
|
Net income from discontinued operations, net of income taxes
|
|
1,132
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,132
|
|
Net income (loss)
|
|
$
|
38,856
|
|
|
$
|
37,519
|
|
|
$
|
—
|
|
|
$
|
(39,406
|
)
|
|
$
|
36,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2012
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Oil and gas revenues
|
|
$
|
4,608
|
|
|
$
|
79,210
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83,818
|
|
Cost and expenses
|
|
32,806
|
|
|
51,429
|
|
|
—
|
|
|
(15,223
|
)
|
|
69,012
|
|
Operating income (loss)
|
|
(28,198
|
)
|
|
27,781
|
|
|
—
|
|
|
15,223
|
|
|
14,806
|
|
Other income (expense), net
|
|
34,170
|
|
|
(7,014
|
)
|
|
—
|
|
|
—
|
|
|
27,156
|
|
Income (loss) from continuing operations before income taxes
|
|
5,972
|
|
|
20,767
|
|
|
—
|
|
|
15,223
|
|
|
41,962
|
|
Income tax (expense) benefit
|
|
(2,041
|
)
|
|
(7,268
|
)
|
|
—
|
|
|
(6,970
|
)
|
|
(16,279
|
)
|
Equity in income (loss) of subsidiaries
|
|
16,320
|
|
|
—
|
|
|
—
|
|
|
(16,320
|
)
|
|
—
|
|
Net income (loss) from continuing operations
|
|
20,251
|
|
|
13,499
|
|
|
—
|
|
|
(8,067
|
)
|
|
25,683
|
|
Net income from discontinued operations, net of income taxes
|
|
—
|
|
|
—
|
|
|
2,821
|
|
|
—
|
|
|
2,821
|
|
Net income (loss)
|
|
$
|
20,251
|
|
|
$
|
13,499
|
|
|
$
|
2,821
|
|
|
$
|
(8,067
|
)
|
|
$
|
28,504
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2013
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Oil and gas revenues
|
|
$
|
3,647
|
|
|
$
|
242,478
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
246,125
|
|
Cost and expenses
|
|
36,433
|
|
|
129,564
|
|
|
—
|
|
|
47
|
|
|
166,044
|
|
Operating income (loss)
|
|
(32,786
|
)
|
|
112,914
|
|
|
—
|
|
|
(47
|
)
|
|
80,081
|
|
Other income (expense), net
|
|
(5,681
|
)
|
|
(12,045
|
)
|
|
—
|
|
|
—
|
|
|
(17,726
|
)
|
Income (loss) from continuing operations before income taxes
|
|
(38,467
|
)
|
|
100,869
|
|
|
—
|
|
|
(47
|
)
|
|
62,355
|
|
Income tax (expense) benefit
|
|
13,463
|
|
|
(35,410
|
)
|
|
—
|
|
|
(2,047
|
)
|
|
(23,994
|
)
|
Equity in income (loss) of subsidiaries
|
|
65,459
|
|
|
—
|
|
|
—
|
|
|
(65,459
|
)
|
|
—
|
|
Net income (loss) from continuing operations
|
|
40,455
|
|
|
65,459
|
|
|
—
|
|
|
(67,553
|
)
|
|
38,361
|
|
Net income from discontinued operations, net of income taxes
|
|
24,790
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,790
|
|
Net income (loss)
|
|
$
|
65,245
|
|
|
$
|
65,459
|
|
|
$
|
—
|
|
|
$
|
(67,553
|
)
|
|
$
|
63,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2012
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Oil and gas revenues
|
|
$
|
11,397
|
|
|
$
|
153,136
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
164,533
|
|
Cost and expenses
|
|
47,352
|
|
|
94,107
|
|
|
—
|
|
|
(14,112
|
)
|
|
127,347
|
|
Operating income (loss)
|
|
(35,955
|
)
|
|
59,029
|
|
|
—
|
|
|
14,112
|
|
|
37,186
|
|
Other income (expense), net
|
|
35,297
|
|
|
(14,560
|
)
|
|
—
|
|
|
—
|
|
|
20,737
|
|
Income (loss) from continuing operations before income taxes
|
|
(658
|
)
|
|
44,469
|
|
|
—
|
|
|
14,112
|
|
|
57,923
|
|
Income tax (expense) benefit
|
|
229
|
|
|
(15,564
|
)
|
|
—
|
|
|
(6,229
|
)
|
|
(21,564
|
)
|
Equity in income (loss) of subsidiaries
|
|
30,473
|
|
|
—
|
|
|
—
|
|
|
(30,473
|
)
|
|
—
|
|
Net income (loss) from continuing operations
|
|
30,044
|
|
|
28,905
|
|
|
—
|
|
|
(22,590
|
)
|
|
36,359
|
|
Net income from discontinued operations, net of income taxes
|
|
—
|
|
|
—
|
|
|
1,568
|
|
|
—
|
|
|
1,568
|
|
Net income (loss)
|
|
$
|
30,044
|
|
|
$
|
28,905
|
|
|
$
|
1,568
|
|
|
$
|
(22,590
|
)
|
|
$
|
37,927
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2013
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Net cash provided by (used in) operating activities - continuing operations
|
|
$
|
4,319
|
|
|
$
|
209,403
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
213,722
|
|
Net cash provided by (used in) investing activities - continuing operations
|
|
(142,476
|
)
|
|
(428,774
|
)
|
|
—
|
|
|
219,183
|
|
|
(352,067
|
)
|
Net cash provided by (used in) financing activities - continuing operations
|
|
(41,521
|
)
|
|
219,183
|
|
|
—
|
|
|
(219,183
|
)
|
|
(41,521
|
)
|
Net cash provided by (used in) discontinued operations
|
|
131,618
|
|
|
—
|
|
|
(519
|
)
|
|
—
|
|
|
131,099
|
|
Net increase (decrease) in cash and cash equivalents
|
|
(48,060
|
)
|
|
(188
|
)
|
|
(519
|
)
|
|
—
|
|
|
(48,767
|
)
|
Cash and cash equivalents, beginning of period
|
|
51,894
|
|
|
201
|
|
|
519
|
|
|
—
|
|
|
52,614
|
|
Cash and cash equivalents, end of period
|
|
$
|
3,834
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,847
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2012
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
|
(In thousands)
|
Net cash provided by operating activities - continuing operations
|
|
$
|
43,723
|
|
|
$
|
101,585
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
145,308
|
|
Net cash provided by (used in) investing activities - continuing operations
|
|
(165,100
|
)
|
|
(188,743
|
)
|
|
—
|
|
|
119,927
|
|
|
(233,916
|
)
|
Net cash provided by (used in) financing activities - continuing operations
|
|
108,986
|
|
|
93,120
|
|
|
—
|
|
|
(119,927
|
)
|
|
82,179
|
|
Net cash used in discontinued operations
|
|
(18
|
)
|
|
—
|
|
|
(896
|
)
|
|
—
|
|
|
(914
|
)
|
Net increase (decrease) in cash and cash equivalents
|
|
(12,409
|
)
|
|
5,962
|
|
|
(896
|
)
|
|
—
|
|
|
(7,343
|
)
|
Cash and cash equivalents, beginning of period
|
|
19,134
|
|
|
7,263
|
|
|
1,715
|
|
|
—
|
|
|
28,112
|
|
Cash and cash equivalents, end of period
|
|
$
|
6,725
|
|
|
$
|
13,225
|
|
|
$
|
819
|
|
|
$
|
—
|
|
|
$
|
20,769
|
|