CRZO 3Q14 Form 10-Q



UNITED STATES
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, 2014
o
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
incorporation or organization)
 
(IRS Employer
Identification No.)
 
500 Dallas Street, Suite 2300, Houston, Texas
 
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  x    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
 
¨  (Do not check if a smaller reporting company)
 
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 October 31, 2014 was 46,096,441.



CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014
INDEX
 
PAGE
 
Item 1.
 
 
 
 
Notes to Consolidated Financial Statements
Item 2.
Item 3.
Item 4.
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.



PART I. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
(Unaudited)
 
 
September 30,
2014
 
December 31,
2013
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 

$7,161

 

$157,439

Accounts receivable, net
 
113,107

 
111,195

Derivative assets
 
20,594

 

Deferred income taxes
 

 
4,201

Other current assets
 
4,297

 
6,926

Total current assets
 
145,159

 
279,761

Property and equipment
 
 
 
 
Oil and gas properties, full cost method
 
 
 
 
Proved properties, net
 
1,747,845

 
1,408,484

Unproved properties, not being amortized
 
499,722

 
377,437

Other property and equipment, net
 
7,580

 
8,294

Total property and equipment, net
 
2,255,147

 
1,794,215

Debt issuance costs
 
20,631

 
22,899

Other assets
 
19,897

 
13,885

Total Assets
 

$2,440,834

 

$2,110,760

 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 

$102,579

 

$57,146

Revenues and royalties payable
 
85,943

 
79,136

Accrued capital expenditures
 
89,022

 
87,031

Accrued interest
 
24,899

 
17,430

Advances for joint operations
 
4,391

 
19,967

Liabilities of discontinued operations
 
8,017

 
10,936

Derivative liabilities
 
135

 
9,947

Deferred income taxes
 
3,659

 

Other current liabilities
 
54,881

 
41,242

Total current liabilities
 
373,526

 
322,835

Long-term debt
 
1,019,791

 
900,247

Liabilities of discontinued operations
 
12,785

 
17,336

Deferred income taxes
 
58,151

 
16,856

Asset retirement obligations
 
10,041

 
6,576

Other liabilities
 
4,661

 
5,306

Total liabilities
 
1,478,955

 
1,269,156

Commitments and contingencies
 

 

Shareholders’ equity
 
 
 
 
Common stock, $0.01 par value, 90,000,000 shares authorized; 46,087,406 issued and outstanding as of September 30, 2014 and 45,468,675 issued and outstanding as of December 31, 2013
 
461

 
455

Additional paid-in capital
 
908,133

 
879,948

Retained earnings (Accumulated deficit)
 
53,285

 
(38,799
)
Total shareholders’ equity
 
961,879

 
841,604

Total Liabilities and Shareholders’ Equity
 

$2,440,834

 

$2,110,760

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
(Unaudited)
 
 Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2014
 
2013
 
2014
 
2013
Revenues
 
 
 
 
 
 
 
Crude oil

$173,277

 

$117,797

 

$469,601

 

$311,084

Natural gas liquids
7,798

 
6,025

 
19,669

 
11,532

Natural gas
15,150

 
20,507

 
57,642

 
67,838

Total revenues
196,225

 
144,329

 
546,912

 
390,454

 
 
 
 
 
 
 
 
Costs and Expenses
 
 
 
 
 
 
 
Lease operating
21,019

 
12,934

 
51,002

 
34,926

Production taxes
8,393

 
5,590

 
22,666

 
14,687

Ad valorem taxes
2,235

 
2,125

 
5,569

 
6,848

Depreciation, depletion and amortization
83,572

 
55,362

 
228,912

 
151,587

General and administrative
9,538

 
19,715

 
65,481

 
53,722

(Gain) loss on derivatives, net
(71,783
)
 
27,658

 
(11,153
)
 
16,486

Interest expense, net
12,201

 
13,402

 
36,557

 
42,367

Other (income) expense, net
549

 
(28
)
 
1,536

 
(95
)
Total costs and expenses
65,724

 
136,758

 
400,570

 
320,528

 
 
 
 
 
 
 
 
Income From Continuing Operations Before Income Taxes
130,501

 
7,571

 
146,342

 
69,926

Income tax expense
(47,504
)
 
(1,859
)
 
(53,510
)
 
(25,853
)
Income From Continuing Operations
82,997

 
5,712

 
92,832

 
44,073

Income (Loss) From Discontinued Operations, Net of Income Taxes
792

 
(1,191
)
 
(748
)
 
23,599

Net Income

$83,789

 

$4,521

 

$92,084

 

$67,672

 
 
 
 
 
 
 
 
Net Income (Loss) Per Common Share - Basic
 
 
 
 
 
 
 
Income from continuing operations

$1.83

 

$0.14

 

$2.05

 

$1.10

Income (loss) from discontinued operations, net of income taxes
0.02

 
(0.03
)
 
(0.02
)
 
0.59

Net income

$1.85

 

$0.11

 

$2.03

 

$1.69

 
 
 
 
 
 
 
 
Net Income (Loss) Per Common Share - Diluted
 
 
 
 
 
 
 
Income from continuing operations

$1.80

 

$0.14

 

$2.01

 

$1.09

Income (loss) from discontinued operations, net of income taxes
0.02

 
(0.03
)
 
(0.01
)
 
0.58

Net income

$1.82

 

$0.11

 

$2.00

 

$1.67

 
 
 
 
 
 
 
 
Weighted Average Common Shares Outstanding
 
 
 
 
 
 
 
Basic
45,257

 
40,386

 
45,277

 
40,083

Diluted
46,029

 
40,927

 
46,109

 
40,601

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
 
Nine Months Ended
September 30,
 
2014
 
2013
Cash Flows From Operating Activities
 
 
 
Net income

$92,084

 

$67,672

(Income) loss from discontinued operations, net of income taxes
748

 
(23,599
)
Adjustments to reconcile income from continuing operations to net cash provided by operating activities from continuing operations
 
 
 
Depreciation, depletion and amortization
228,912

 
151,587

Non-cash (gain) loss on derivatives, net
(36,652
)
 
25,806

Stock-based compensation
28,209

 
19,338

Deferred income taxes
48,908

 
25,853

Non-cash interest expense, net
2,021

 
3,217

Other, net
(1,705
)
 
1,789

Changes in operating assets and liabilities-
 
 
 
Accounts receivable
(1,767
)
 
1,910

Accounts payable
33,024

 
38,843

Accrued liabilities
(771
)
 
2,049

Other, net
(4,324
)
 
(4,212
)
Net cash provided by operating activities from continuing operations
388,687

 
310,253

Net cash used in operating activities from discontinued operations
(1,162
)
 
(400
)
Net cash provided by operating activities
387,525

 
309,853

Cash Flows From Investing Activities
 
 
 
Capital expenditures - oil and gas properties
(665,517
)
 
(548,049
)
Capital expenditures - other property and equipment
(569
)
 
(687
)
Proceeds from sales of oil and gas properties, net
10,487

 
20,753

Other, net
1,418

 
24,582

Net cash used in investing activities from continuing operations
(654,181
)
 
(503,401
)
Net cash provided by (used in) investing activities from discontinued operations
(6,773
)
 
126,223

Net cash used in investing activities
(660,954
)
 
(377,178
)
Cash Flows From Financing Activities
 
 
 
Proceeds from borrowings and issuances
646,000

 
437,000

Debt repayments
(527,000
)
 
(419,325
)
Payments of debt issuance costs
(594
)
 
(1,075
)
Excess tax benefits from stock-based compensation
4,602

 

Proceeds from stock options exercised
143

 
839

Net cash provided by financing activities from continuing operations
123,151

 
17,439

Net cash provided by financing activities from discontinued operations

 
3,000

Net cash provided by financing activities
123,151

 
20,439

Net Decrease in Cash and Cash Equivalents
(150,278
)
 
(46,886
)
Cash and Cash Equivalents, Beginning of Period
157,439

 
52,614

Cash and Cash Equivalents, End of Period

$7,161

 

$5,728

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.
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 Utica Shale in Ohio, the Niobrara Formation in Colorado, and the Marcellus Shale in Pennsylvania.
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 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 to present fairly, in all material respects, 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 periods presented are not necessarily indicative of the results that may 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, 2013.
Reclassifications
Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.
Discontinued Operations
On February 22, 2013, the Company closed on the sale of Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“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 liabilities, results of operations and cash flows associated with Carrizo UK have been classified as discontinued operations in the consolidated financial statements. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to 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 depreciation, depletion, and amortization (“DD&A”) 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 estimated costs and timing of cash outflows underlying 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 the Company’s estimates. Other significant estimates are involved in determining impairments of unevaluated

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leasehold costs, fair values of derivative assets and liabilities, stock-based compensation, collectability of receivables, and in evaluating disputed claims, interpreting 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 and completion, 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 equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $47.5 million and $2.2 million as of September 30, 2014 and December 31, 2013, respectively.
Accounts Receivable and Accounts Payable
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. The allowance for doubtful accounts was not significant at September 30, 2014 and December 31, 2013. Accounts receivable from related parties at September 30, 2014 and December 31, 2013 was $0.1 million and $6.6 million, respectively. Accounts payable to related parties at September 30, 2014 and December 31, 2013 was $1.3 million and $2.8 million, respectively.
Concentration of Credit Risk
The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from customers and joint interest owners in the oil and gas industry 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 and joint interest owners. The Company generally has the right to withhold future revenue distributions to recover any non-payment of joint interest billings.
The Company’s derivative instruments in a net asset position also subject the Company to a concentration of credit risk. See “Note 8. 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 cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled $3.4 million and $3.8 million for the three months ended September 30, 2014 and 2013, respectively, and $14.1 million and $10.1 million for the nine months ended September 30, 2014 and 2013, 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 natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate 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 DD&A per Boe of proved oil and gas properties was $26.75 and $19.75 for the three months ended September 30, 2014 and 2013, respectively, and $26.58 and $19.34 for the nine months ended September 30, 2014 and 2013, respectively.
Unproved properties, 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. Exploratory wells in progress and individually significant unevaluated leaseholds are assessed 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 along with associated capitalized interest 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 and completion capital expenditure plans. The Company expects to complete its evaluation of the majority of its unevaluated leaseholds within the next five years and exploratory wells in progress within the next year. Individually insignificant unevaluated leaseholds are grouped by major area and added to the oil and gas property costs subject to amortization

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based on the average primary lease term of the properties. The Company capitalized interest costs associated with its unproved properties totaling $8.7 million and $7.5 million for the three months ended September 30, 2014 and 2013, respectively, and $25.0 million and $21.8 million for the nine months ended September 30, 2014 and 2013, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties using a weighted-average interest rate based on outstanding borrowings.
Proceeds from the sale of proved and unproved 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. For the three and nine months ended September 30, 2014, the Company did not have any sales of oil and gas properties that significantly altered such relationship.
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 unproved properties not being amortized, 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 in the future increase the cost center ceiling applicable to the subsequent period.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized 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 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.
Debt Issuance Costs
Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes.
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities 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 assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as borrowings bear interest at variable rates of interest. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of any unamortized discount and 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 asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or when the production equipment and facilities are installed with an associated increase in oil and gas property costs. Asset retirement obligations are accreted to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. On an interim basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are

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necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells.
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 production is 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 whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production 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 reserves. Sales volumes are not significantly different from the Company’s share of production and as of September 30, 2014 and December 31, 2013, the Company did not have any material production imbalances.
Derivative Instruments
The Company uses commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce its exposure to commodity price volatility for a substantial, but varying, portion of its forecasted oil and gas production up to 36 months and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. All derivative instruments are recorded on the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, 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 in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes.
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. See “Note 8. Derivative Instruments” for further discussion of the Company’s derivative instruments.
Stock-Based Compensation
The Company recognized the following stock-based compensation expense (benefit) associated with stock appreciation rights to be settled in cash (“SARs”), restricted stock awards and units and performance share awards for the periods indicated which is reflected as general and administrative expense in the consolidated statements of income:
 
 
 Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
Stock appreciation rights
 

($8,935
)
 

$6,752

 

$10,637

 

$10,691

Restricted stock awards and units
 
8,592

 
5,232

 
22,517

 
13,551

Performance share awards
 
592

 

 
925

 

 
 
249

 
11,984

 
34,079

 
24,242

Less: amounts capitalized
 
(1,179
)
 
(2,112
)
 
(5,870
)
 
(4,904
)
Total stock-based compensation expense (benefit)
 

($930
)
 

$9,872

 

$28,209

 

$19,338

Income tax benefit (expense)
 

($326
)
 

$3,627

 

$9,874

 

$7,097

Stock Appreciation Rights. For SARs, stock-based compensation expense is based on the fair value liability (using the Black-Scholes-Merton option pricing model) remeasured at each reporting period, recognized over the vesting period (generally three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at each reporting period based on the intrinsic value of the SAR. The liability for SARs are classified as “Other current liabilities” for the portion of the awards that are vested or are expected to vest within the

-8-


next 12 months, with the remainder classified as “Other liabilities.” SARs typically expire between four and seven years after the date of grant.
Restricted Stock Awards and Units. For restricted stock awards and units granted to employees, stock-based compensation expense is based on the price of the Company’s common stock on the grant date 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. 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.
Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant-date fair value (using a Monte Carlo valuation model) and recognized over the three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting range from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to an industry peer group over a three year performance period.
Income Taxes
Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets by taxing jurisdiction and considers its estimate of future taxable income based on 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 benefit from 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.
Income From Continuing Operations Per Common Share
Supplemental income from continuing operations per common share information is provided below:
 
 
 Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands, except per share data)
Income From Continuing Operations
 

$82,997

 

$5,712

 

$92,832

 

$44,073

Basic weighted average common shares outstanding
 
45,257

 
40,386

 
45,277

 
40,083

Effect of dilutive instruments
 
772

 
541

 
832

 
518

Diluted weighted average common shares outstanding
 
46,029

 
40,927

 
46,109

 
40,601

Income From Continuing Operations Per Common Share
 
 
 
 
 
 
 
 
Basic
 

$1.83

 

$0.14

 

$2.05

 

$1.10

Diluted
 

$1.80

 

$0.14

 

$2.01

 

$1.09

Basic income from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted 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, performance share awards, stock options and warrants. The Company excludes the number of awards, units, options and warrants from the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are greater than the average market prices of the Company’s common stock for the corresponding period as the effect would be antidilutive to the computation. The Company includes the number of potentially dilutive common shares attributable to the performance share awards based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. The number of awards, units, options, warrants and performance share awards excluded for the three and nine months ended September 30, 2014 and 2013 were not significant.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry specific guidance in Subtopic 932-605, Extractive Activities- Oil and Gas- Revenue Recognition. This ASU requires entities to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. This ASU is effective for annual and interim periods

-9-


beginning in 2017, and is required to be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its 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 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 liabilities of discontinued operations of $20.8 million and $28.3 million as of September 30, 2014 and December 31, 2013, respectively, 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 liabilities related to the sale of Carrizo UK.
The following table summarizes the amounts included in income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of income for the three and nine months ended September 30, 2014 and 2013:
 
 
 Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
Revenues
 

$—

 

$—

 

$—

 

$—

 
 
 
 
 
 
 
 
 
Costs and Expenses
 
 
 
 
 
 
 
 
General and administrative
 
259

 
408

 
1,162

 
709

Accretion related to asset retirement obligations
 

 

 

 
36

Gain on sale of discontinued operations
 

 

 

 
(37,294
)
Increase (decrease) in estimated future obligations
 
(2,144
)
 
1,187

 
(696
)
 
(1,378
)
Loss on derivatives, net
 
16

 
18

 
34

 
93

Other (income) expense, net
 

 
(106
)
 

 
(438
)
Income (Loss) From Discontinued Operations Before Income Taxes
 
1,869

 
(1,507
)
 
(500
)
 
38,272

Income tax (expense) benefit
 
(1,077
)
 
316

 
(248
)
 
(14,673
)
Income (Loss) From Discontinued Operations, Net of Income Taxes
 

$792

 

($1,191
)
 

($748
)
 

$23,599

Income Taxes
Carrizo UK is a disregarded entity for U.S. federal 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 sheets.

-10-


4. Property and Equipment, Net
As of September 30, 2014 and December 31, 2013, total property and equipment, net consisted of the following:
 
 
September 30,
2014
 
December 31,
2013
 
 
(In thousands)
Proved properties
 

$2,747,915

 

$2,182,226

Accumulated depreciation, depletion and amortization
 
(1,000,070
)
 
(773,742
)
Proved properties, net
 
1,747,845

 
1,408,484

Unproved properties, not being amortized
 
 
 
 
Unevaluated leasehold and seismic costs
 
388,169

 
302,232

Exploratory wells in progress
 
49,171

 
30,196

Capitalized interest
 
62,382

 
45,009

Total unproved properties, not being amortized
 
499,722

 
377,437

Other property and equipment
 
15,855

 
15,260

Accumulated depreciation
 
(8,275
)
 
(6,966
)
Other property and equipment, net
 
7,580

 
8,294

Total property and equipment, net
 

$2,255,147

 

$1,794,215

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 discrete item 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 rates 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 rates 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
September 30,
 
Nine Months Ended
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
Income tax expense at the statutory rate
 

($45,675
)
 

($2,650
)
 

($51,220
)
 

($24,474
)
State income taxes, net of U.S. federal income tax effect
 
(2,560
)
 
791

 
(2,974
)
 
(1,275
)
Other, net
 
731

 

 
684

 
(104
)
Income tax expense
 

($47,504
)
 

($1,859
)
 

($53,510
)
 

($25,853
)

-11-


6. Long-Term Debt
Long-term debt consisted of the following as of September 30, 2014 and December 31, 2013:
 
 
September 30,
2014
 
December 31,
2013
 
 
(In thousands)
8.625% Senior Notes due 2018
 

$600,000

 

$600,000

Unamortized discount for 8.625% Senior Notes
 
(3,634
)
 
(4,178
)
7.50% Senior Notes due 2020
 
300,000

 
300,000

Other long-term debt due 2028
 
4,425

 
4,425

Senior Secured Revolving Credit Facility due 2018
 
119,000

 

Total long-term debt
 

$1,019,791

 

$900,247

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) $1.0 billion. The revolving credit facility matures on July 2, 2018. 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 Material Domestic Subsidiaries (as defined in the credit agreement governing the revolving credit facility). As of September 30, 2014, the Company’s borrowing base was $570.0 million. 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. See “Note 11. Subsequent Events” for further discussion of the borrowing base.
The Company is subject to certain covenants under the terms of the revolving credit facility, as amended, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00; and (2) a Current Ratio of not less than 1.00 to 1.00; (each of the capitalized terms used in the foregoing clauses (1) and (2) being as defined in the credit agreement governing the revolving credit facility). As of September 30, 2014, the ratio of Total Debt to EBITDA was 2.02 to 1.00 and the Current Ratio was 1.68 to 1.00. As defined in the credit agreement governing the revolving credit facility, Total Debt is net of cash and cash equivalents and the Current Ratio includes an add back of the available borrowing capacity. 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 from operations, capital expenditures, sales of oil and gas properties and securities offerings.
As of September 30, 2014, the Company had $119.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 2.01%. As of September 30, 2014, the Company also had $0.6 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. The amount available for borrowing 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 revolving credit facility is generally used to fund ongoing working capital needs and the Company’s capital expenditure plan to the extent such amounts exceed cash flows 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 currently 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 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 commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce its exposure to commodity price volatility for a substantial, but varying, portion of its forecasted oil and gas production up to 36 months and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not enter into derivative instruments for speculative or trading purposes.

-12-


The Company typically has numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value of derivative instruments where the Company is in a net asset position with its counterparties as of September 30, 2014 and December 31, 2013 totaled $36.0 million and $9.3 million, respectively, and is summarized by counterparty in the table below:
Counterparty
 
September 30, 2014
 
December 31, 2013
Wells Fargo
 
41
%
 
23
%
Credit Suisse
 
23
%
 
46
%
Societe Generale
 
22
%
 
31
%
Regions
 
8
%
 
%
Union Bank
 
4
%
 
%
Royal Bank of Canada
 
2
%
 
%
Total
 
100
%
 
100
%
The counterparties to the Company’s derivative instruments are lenders under the Company’s credit agreement. Because each of the lenders have investment grade credit ratings, the Company believes it has minimal credit risk and accordingly does not currently require its counterparties to post collateral to support the net 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.
The fair value of derivative instruments where the Company is in a net liability position with its counterparties as of September 30, 2014 and December 31, 2013 totaled $0.2 million and $10.1 million, respectively.
For the three months ended September 30, 2014 and 2013, the Company recorded in the consolidated statements of income a gain on derivative instruments, net of $71.8 million and a loss on derivative instruments, net of $27.7 million, respectively. For the nine months ended September 30, 2014 and 2013, the Company recorded in the consolidated statements of income a gain on derivative instruments, net of $11.2 million and a loss on derivative instruments, net of $16.5 million, respectively.
The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of September 30, 2014:
Period    
 
Type of Contract
 
Volumes
(in Bbls/d)
 
Weighted
Average
Floor  Price
($/Bbl)
 
Weighted
Average
Ceiling  Price
($/Bbl)
 
Weighted
Average
Short Put  Price
($/Bbl)
 
Weighted
Average
Put Spread
($/Bbl)
October - December 2014
 
Fixed Price Swaps
 
11,500

 

$93.55

 


 
 
 
 
 
 
Costless Collars
 
3,000

 

$88.33

 

$104.26

 
 
 
 
 
 
Three-way Collars
 
500

 

$85.00

 

$107.75

 

$65.00

 

$20.00

January - December 2015
 
Fixed Price Swaps
 
10,370

 

$92.97

 


 
 
 
 
 
 
Costless Collars
 
700

 

$90.00

 

$100.65

 
 
 
 
 
 
Three-way Collars
 
1,000

 

$85.00

 

$105.00

 

$65.00

 

$20.00

January - December 2016
 
Fixed Price Swaps
 
3,000

 

$91.09

 
 
 
 
 
 
 
 
Three-way Collars
 
667

 

$85.00

 

$104.00

 

$65.00

 

$20.00

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of September 30, 2014:
Period    
 
Type of Contract
 
Volumes
(in MMBtu/d)
 
Weighted
Average
Floor Price
($/MMBtu)
 
Weighted
Average
Ceiling Price
($/MMBtu)
October - December 2014
 
Fixed Price Swaps
 
54,380

 

$4.16

 


 
 
Calls
 
10,000

 


 

$5.50

January - December 2015
 
Fixed Price Swaps
 
30,000

 

$4.29

 



-13-


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 summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of September 30, 2014 and December 31, 2013. All items included in the tables below are Level 2 inputs within the fair value hierarchy:
 
 
September 30, 2014
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
 
 
(In thousands)
Derivative assets
 
 
 
 
 
 
Derivative assets
 

$22,873

 

($2,279
)
 

$20,594

Other assets
 
16,328

 
(921
)
 
15,407

Derivative liabilities
 
 
 
 
 
 
Derivative liabilities
 
(2,414
)
 
2,279

 
(135
)
Other liabilities
 
(986
)
 
921

 
(65
)
Total
 

$35,801

 

$—

 

$35,801

 
 
December 31, 2013
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
 
 
(In thousands)
Derivative assets
 
 
 
 
 
 
Derivative assets
 

$2,389

 

($2,389
)
 

$—

Other assets
 
11,709

 
(2,425
)
 
9,284

Derivative liabilities
 
 
 
 
 
 
Derivative liabilities
 
(12,336
)
 
2,389

 
(9,947
)
Other liabilities
 
(2,613
)
 
2,425

 
(188
)
Total
 

($851
)
 

$—

 

($851
)
The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values 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 derivative asset and liability 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 Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the

-14-


contract and in the event of default or termination of the contract. The Company had no transfers in or out of Levels 1 or 2 for the nine months ended September 30, 2014 or 2013.
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 other long-term debt, based on quoted market prices, as of September 30, 2014 and December 31, 2013.
 
 
September 30, 2014
 
December 31, 2013
 
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
 
(In thousands)
8.625% Senior Notes due 2018
 

$596,366

 

$627,750

 

$595,822

 

$644,978

7.50% Senior Notes due 2020
 
300,000

 
312,750

 
300,000

 
327,000

Other long-term debt due 2028
 
4,425

 
4,027

 
4,425

 
4,115

10. Condensed Consolidating Financial Information
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 September 30, 2014 and December 31, 2013, and for the three and nine months ended September 30, 2014 and 2013 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.

-15-


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
(Unaudited)
 
 
September 30, 2014
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Total current assets
 

$1,884,949

 

$255,806

 

$—

 

($1,995,596
)
 

$145,159

Total property and equipment, net
 
21,518

 
2,179,872

 
27,091

 
26,666

 
2,255,147

Investment in subsidiaries
 
209,557

 

 

 
(209,557
)
 

Other assets
 
116,135

 

 

 
(75,607
)
 
40,528

Total Assets
 

$2,232,159

 

$2,435,678

 

$27,091

 

($2,254,094
)
 

$2,440,834

 
 
 
 
 
 
 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$245,703

 

$2,096,326

 

$27,094

 

($1,995,597
)
 

$373,526

Long-term liabilities
 
1,037,586

 
129,792

 

 
(61,949
)
 
1,105,429

Total shareholders’ equity
 
948,870

 
209,560

 
(3
)
 
(196,548
)
 
961,879

Total Liabilities and Shareholders’ Equity
 

$2,232,159

 

$2,435,678

 

$27,091

 

($2,254,094
)
 

$2,440,834

 
 
December 31, 2013
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Total current assets
 

$1,820,069

 

$168,718

 

$—

 

($1,709,026
)
 

$279,761

Total property and equipment, net
 
2,797

 
1,768,553

 
2,058

 
20,807

 
1,794,215

Investment in subsidiaries
 
61,619

 

 

 
(61,619
)
 

Other assets
 
69,686

 

 

 
(32,902
)
 
36,784

Total Assets
 

$1,954,171

 

$1,937,271

 

$2,058

 

($1,782,740
)
 

$2,110,760

 
 
 
 
 
 
 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$201,486

 

$1,828,314

 

$2,061

 

($1,709,026
)
 

$322,835

Long-term liabilities
 
922,571

 
47,335

 

 
(23,585
)
 
946,321

Total shareholders’ equity
 
830,114

 
61,622

 
(3
)
 
(50,129
)
 
841,604

Total Liabilities and Shareholders’ Equity
 

$1,954,171

 

$1,937,271

 

$2,058

 

($1,782,740
)
 

$2,110,760


-16-


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(in thousands)
(Unaudited)
 
 
Three Months Ended September 30, 2014
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$924

 

$195,301

 

$—

 

$—

 

$196,225

Total costs and expenses
 
(42,829
)
 
116,622

 

 
(8,069
)
 
65,724

Income from continuing operations before income taxes
 
43,753

 
78,679

 

 
8,069

 
130,501

Income tax expense
 
(15,312
)
 
(27,538
)
 

 
(4,654
)
 
(47,504
)
Equity in income of subsidiaries
 
51,141

 

 

 
(51,141
)
 

Income from continuing operations
 
79,582

 
51,141

 

 
(47,726
)
 
82,997

Income from discontinued operations, net of income taxes
 
792

 

 

 

 
792

Net income
 

$80,374

 

$51,141

 

$—

 

($47,726
)
 

$83,789

 
 
Three Months Ended September 30, 2013
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$2,428

 

$141,901

 

$—

 

$—

 

$144,329

Total costs and expenses
 
57,308

 
79,358

 

 
92

 
136,758

Income (loss) from continuing operations before income taxes
 
(54,880
)
 
62,543

 

 
(92
)
 
7,571

Income tax (expense) benefit
 
19,208

 
(21,784
)
 

 
717

 
(1,859
)
Equity in income of subsidiaries
 
40,759

 

 

 
(40,759
)
 

Income from continuing operations
 
5,087

 
40,759

 

 
(40,134
)
 
5,712

Loss from discontinued operations, net of income taxes
 
(1,191
)
 

 

 

 
(1,191
)
Net income
 

$3,896

 

$40,759

 

$—

 

($40,134
)
 

$4,521



-17-


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30, 2014
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$3,696

 

$543,216

 

$—

 

$—

 

$546,912

Total costs and expenses
 
90,811

 
315,619

 

 
(5,860
)
 
400,570

Income (loss) from continuing operations before income taxes
 
(87,115
)
 
227,597

 

 
5,860

 
146,342

Income tax (expense) benefit
 
30,491

 
(79,659
)
 

 
(4,342
)
 
(53,510
)
Equity in income of subsidiaries
 
147,938

 

 

 
(147,938
)
 

Income from continuing operations
 
91,314

 
147,938

 

 
(146,420
)
 
92,832

Loss from discontinued operations, net of income taxes
 
(748
)
 

 

 

 
(748
)
Net income
 

$90,566

 

$147,938

 

$—

 

($146,420
)
 

$92,084

 
 
Nine Months Ended September 30, 2013
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$6,075

 

$384,379

 

$—

 

$—

 

$390,454

Total costs and expenses
 
99,422

 
220,967

 

 
139

 
320,528

Income (loss) from continuing operations before income taxes
 
(93,347
)
 
163,412

 

 
(139
)
 
69,926

Income tax (expense) benefit
 
32,671

 
(57,194
)
 

 
(1,330
)
 
(25,853
)
Equity in income of subsidiaries
 
106,218

 

 

 
(106,218
)
 

Income from continuing operations
 
45,542

 
106,218

 

 
(107,687
)
 
44,073

Income from discontinued operations, net of income taxes
 
23,599

 

 

 

 
23,599

Net income
 

$69,141

 

$106,218

 

$—

 

($107,687
)
 

$67,672


-18-


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
 
Nine Months Ended September 30, 2014
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities from continuing operations
 

($132,889
)
 

$521,576

 

$—

 

$—

 

$388,687

Net cash used in investing activities from continuing operations
 
(132,605
)
 
(632,160
)
 
(24,717
)
 
135,301

 
(654,181
)
Net cash provided by financing activities from continuing operations
 
123,151

 
110,584

 
24,717

 
(135,301
)
 
123,151

Net cash used in discontinued operations
 
(7,935
)
 

 

 

 
(7,935
)
Net decrease in cash and cash equivalents
 
(150,278
)
 

 

 

 
(150,278
)
Cash and cash equivalents, beginning of period
 
157,439

 

 

 

 
157,439

Cash and cash equivalents, end of period
 

$7,161

 

$—

 

$—

 

$—

 

$7,161

 
 
Nine Months Ended September 30, 2013
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities from continuing operations
 

($22,222
)
 

$332,475

 

$—

 

$—

 

$310,253

Net cash used in investing activities from continuing operations
 
(170,725
)
 
(601,936
)
 
(1,624
)
 
270,884

 
(503,401
)
Net cash provided by financing activities from continuing operations
 
17,439

 
269,260

 
1,624

 
(270,884
)
 
17,439

Net cash provided by (used in) discontinued operations
 
129,342

 

 
(519
)
 

 
128,823

Net decrease in cash and cash equivalents
 
(46,166
)
 
(201
)
 
(519
)
 

 
(46,886
)
Cash and cash equivalents, beginning of period
 
51,894

 
201

 
519

 

 
52,614

Cash and cash equivalents, end of period
 

$5,728

 

$—

 

$—

 

$—

 

$5,728



-19-


11. Subsequent Events
On October 7, 2014, a fifth amendment to the credit agreement governing the revolving credit facility (the “Fifth Amendment”) was executed. The Fifth Amendment (i) permitted the Company to increase or decrease the aggregate principal amount of the commitments of the lenders under the credit agreement governing the revolving credit facility provided that the aggregate commitments do not exceed the then existing borrowing base, (ii) increased the letter of credit facility from $15.0 million to $30.0 million, (iii) established an approved borrowing base of $675.0 million until the next redetermination and (iv) amended the availability of issuances of additional senior notes. As a result of the Fall 2014 borrowing base redetermination, effective October 7, 2014, the borrowing base was increased to $675.0 million from $570.0 million. However, the Company voluntarily elected to limit the lenders’ aggregate commitment to $585.0 million. Prior to giving effect to the amendment, the revolving credit facility provided availability for issuances of additional senior notes in the aggregate principal amount of up to $350.0 million. The amendment replaced this limitation to permit unlimited issuances of additional senior notes as long as, subject to certain other conditions described therein, after giving effect to the issuance of the additional senior notes, the Company is in compliance with our financial covenants under the credit agreement governing our revolving credit facility.
On October 24, 2014, the Company completed the acquisition of oil and gas properties from Eagle Ford Minerals, LLC (“EFM”) primarily in LaSalle, Atascosa and McMullen Counties, Texas in the Eagle Ford Shale (the “Eagle Ford Shale Transaction”). The transaction had an effective date of October 1, 2014, with an adjusted purchase price of $243.0 million, which represents an agreed upon price of $250.0 million less working capital adjustments. The Company paid approximately $93.0 million at closing, which was funded from borrowings under the revolving credit facility that were repaid with net proceeds from the senior note offering discussed below. The Company is required to pay the remaining $150.0 million no later than February 16, 2015, which will be funded with borrowings under the revolving credit facility. Prior to the acquisition, the Company and EFM were joint working interest owners in the properties that were subject to the transaction, for which the Company acted as the operator and owned an approximate 75% working interest in nearly all of such properties. After giving effect to the transaction, the Company holds an approximate 100% working interest in nearly all of the acquired properties.
In conjunction with the Eagle Ford Shale Transaction described above, the borrowing base was increased to $800.0 million from $675.0 million. However, the Company voluntarily elected to limit the lenders’ aggregate commitment to $685.0 million. The lenders’ aggregate commitment can be increased at any time to the full $800.0 million by requesting one or more lenders to approve an increase to their commitment. The borrowing base will be redetermined by the lenders at least semi-annually on or around each May 1 and November 1, with the next redetermination expected in the Spring of 2015. 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.
On October 30, 2014, the Company issued $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020 at a price to the initial purchasers of 100.50% of par in a private placement. These notes have substantially identical terms, other than with respect to certain transfer restrictions and registration rights, to the Company’s existing 7.50% Senior Notes due 2020 that were issued on September 10, 2012, although the new 7.50% Senior Notes were issued as a separate series of securities. The Company intends to use the net proceeds of approximately $299.8 million, net of offering costs, to fund the Eagle Ford Shale Transaction as described above, repay amounts outstanding under its revolving credit facility and for general corporate purposes.


-20-


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is management’s discussion and analysis of the significant factors that affected the Company’s financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the discussion under “Item 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013, and the unaudited consolidated financial statements included in this quarterly report.
General Overview
For the third quarter of 2014, we recognized total revenues of $196.2 million and production of 3.1 MMBoe. The key drivers to our success for the three months ended September 30, 2014 included the following:
Drilling. See the table below for details of our operated drilling and completion activity in our primary areas of activity:
 
 
Three Months Ended September 30, 2014
 
As of September 30, 2014
 
 
Drilled
 
Wells Brought on Production
 
Waiting on Completion
 
Producing
 
Rig count
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
Eagle Ford
 
15

 
13.1

 
20

 
15.8

 
16

 
13.0

 
182

 
142.0

 
3

Niobrara
 
9

 
3.5

 
7

 
3.3

 
4

 
1.3

 
107

 
44.2

 
1

Marcellus
 

 

 

 

 
11

 
4.4

 
81

 
26.0

 

Utica
 

 

 

 

 

 

 
1

 
0.9

 
1

Total
 
24

 
16.6

 
27

 
19.1

 
31

 
18.7

 
371

 
213.1

 
5


Production. Our third quarter 2014 crude oil production of 1.8 MMBbls, or 20,000 Bbls/d, increased 64% from our third quarter 2013 production of 1.1 MMBbls, or 12,228 Bbls/d, primarily due to production from new wells in the Eagle Ford. Our third quarter 2014 natural gas production of 5.9 Bcf, or 63,630 Mcf/d, decreased 32% from our third quarter 2013 production of 8.6 Bcf, or 93,511 Mcf/d. This was primarily due to the sale of our remaining oil and gas properties in the Barnett to EnerVest Energy Institution Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P., and EV Properties, L.P. (collectively, “EnerVest”) in October 2013 partially offset by production from new wells in Marcellus.
Prices. Our average realized crude oil price during the third quarter of 2014 was $94.17 per Bbl, a 10% decrease as compared to our average realized price of $104.71 per Bbl in the same period in 2013. Our average realized natural gas price during the third quarter of 2014 increased 9% to $2.59 per Mcf from $2.38 per Mcf in the same period in 2013. Commodity prices are affected by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Our financial results are largely dependent on commodity prices, which are beyond our control and have been and are expected to remain volatile.
Recent Developments
The Eagle Ford Shale Transaction. On October 24, 2014, we completed the acquisition of additional leasehold and producing interests in the Eagle Ford Shale (the “Eagle Ford Shale Transaction”) from Eagle Ford Minerals, LLC (“EFM”). The properties acquired in the Eagle Ford Shale Transaction include approximately 6,820 net acres and 20.1 net producing wells located primarily in LaSalle, Atascosa and McMullen Counties, Texas. We estimate that net production from the acquired interests in the properties was approximately 2,260 Bbls/d and 2,457 Mcfe/d for the three months ended September 30, 2014.
Prior to the acquisition, we and EFM were joint working interest owners in the properties that were the subject of the transaction, for which we acted as the operator and owned a 75% working interest in nearly all of such properties. After giving effect to the transaction, we hold an approximate 100% working interest in all of the acquired properties. The transaction had an effective date of October 1, 2014, with a purchase price of $243.0 million in cash, net of working capital adjustments, of which we paid EFM approximately $93.0 million on October 24, 2014 and are required to pay the remaining $150.0 million no later than February 16, 2015. The agreement provides for post-closing purchase price adjustments and indemnities.
We intend to use the net proceeds from the offering described below to fund the Eagle Ford Shale Transaction purchase price of $243.0 million, net of working capital adjustments, and for general corporate purposes. $93.0 million of the Eagle Ford Shale Transaction purchase price was paid at the closing of such transaction, and was funded from borrowings under our revolving credit facility that were repaid with net proceeds from the senior notes offering described below. The remaining $150.0 million will be paid on a deferred basis no later than February 16, 2015 with borrowings under the revolving credit facility. Until net proceeds

-21-


are used to pay the deferred portion of the Eagle Ford Shale Transaction purchase price, net proceeds of such offering will be used to repay amounts outstanding under our revolving credit facility.
Senior Notes Offering. On October 30, 2014, we completed a private placement of $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020 at a price equal to 100.50% of par, plus accrued interest from September 15, 2014. The use of net proceeds of $299.8 million is described above under “The Eagle Ford Shale Transaction.” The new 7.50% Senior Notes have substantially identical terms, other than with respect to transfer restrictions and registration rights, as our original 7.50% Senior Notes due 2020 that were issued on September 10, 2012 (the “Original 7.50% Senior Notes”), although the new 7.50% Senior Notes were issued as a separate series of securities.
The 7.50% Senior Notes bear interest at a rate of 7.50% per annum and will mature on September 15, 2020. We may redeem all or a portion of the 7.50% Senior Notes at any time on or after September 15, 2016 at varying redemption prices. Before September 15, 2016, we may, at our option, redeem all or a portion of the notes at 100% of the principal amount plus a make-whole premium. In addition, prior to September 15, 2015, we may, at our option, redeem up to 35% of the aggregate principal amount of the 7.50% Senior Notes with the proceeds of certain equity offerings at a specified redemption price. Holders of the 7.50% Senior Notes may require us to repurchase some or all of their 7.50% Senior Notes for cash in the event of certain fundamental changes, at 101% of the amount plus accrued and unpaid interest.


-22-


Results of Operations
Three Months Ended September 30, 2014, Compared to the Three Months Ended September 30, 2013
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended September 30, 2014 and 2013:
 
 
 Three Months Ended
September 30,
 
2014 Period
Compared to 2013 Period
 
 
2014
 
2013
 
Increase (Decrease)
 
% Increase (Decrease)
Total production volumes -
 
 
 
 
 
 
 
 
    Crude oil (MBbls)
 
1,840

 
1,125

 
715

 
64
%
    NGLs (MBbls)
 
274

 
202

 
72

 
36
%
    Natural gas (MMcf)
 
5,854

 
8,603

 
(2,749
)
 
(32
%)
        Total Natural gas and NGLs (MMcfe)
 
7,498


9,815

 
(2,317
)
 
(24
%)
Total barrels of oil equivalent (MBoe)
 
3,090


2,761

 
329

 
12
%
 
 
 
 
 
 
 
 
 
Daily production volumes by product -
 
 
 
 
 
 
 
 
    Crude oil (Bbls/d)
 
20,000

 
12,228

 
7,772

 
64
%
    NGLs (Bbls/d)
 
2,978

 
2,196

 
782

 
36
%
    Natural gas (Mcf/d)
 
63,630

 
93,511

 
(29,881
)
 
(32
%)
        Total Natural gas and NGLs (Mcfe/d)
 
81,500

 
106,685

 
(25,185
)
 
(24
%)
Total barrels of oil equivalent (Boe/d)
 
33,587

 
30,011

 
3,576

 
12
%
 
 
 
 
 
 
 
 
 
Daily production volumes by region (Boe/d) -
 
 
 
 
 
 
 
 
    Eagle Ford
 
23,153

 
13,960

 
9,193

 
66
%
    Niobrara
 
2,790

 
2,061

 
729

 
35
%
    Barnett
 

 
7,609

 
(7,609
)
 
(100
%)
    Marcellus
 
7,348

 
6,069

 
1,279

 
21
%
    Utica and other
 
296

 
312

 
(16
)
 
(5
%)
Total barrels of oil equivalent (Boe/d)
 
33,587

 
30,011

 
3,576

 
12
%
 
 
 
 
 
 
 
 
 
Average realized prices -
 
 
 
 
 
 
 
 
    Crude oil ($ per Bbl)
 

$94.17

 

$104.71

 

($10.54
)
 
(10
%)
    NGLs ($ per Bbl)
 
28.46

 
29.83

 
(1.37
)
 
(5
%)
    Natural gas ($ per Mcf)
 
2.59

 
2.38

 
0.21

 
9
%
        Total Natural gas and NGLs ($ per Mcfe)
 

$3.06

 

$2.70

 

$0.36

 
13
%
Total average realized price ($ per Boe)
 

$63.50

 

$52.27

 

$11.23

 
21
%
 
 
 
 
 
 
 
 
 
Revenues (In thousands) -
 
 
 
 
 
 
 
 
    Crude oil
 

$173,277

 

$117,797

 

$55,480

 
47
%
    NGLs
 
7,798

 
6,025

 
1,773

 
29
%
    Natural gas
 
15,150

 
20,507

 
(5,357
)
 
(26
%)
Total revenues
 

$196,225

 

$144,329

 

$51,896

 
36
%
Revenues for the three months ended September 30, 2014 increased 36% to $196.2 million from $144.3 million for the same period in 2013 primarily due to the significant increase in oil production, partially offset by the decrease in oil prices. Production volumes for the three months ended September 30, 2014 and 2013 were 3.1 and 2.8 MMBoe, respectively. The increase in production from the third quarter of 2013 to the third quarter of 2014 was primarily due to increased production from new wells in the Eagle Ford, partially offset by normal production declines and the sale of Barnett to EnerVest in October 2013. Average realized oil prices decreased 10% to $94.17 per Bbl in the third quarter of 2014 from $104.71 per Bbl in the same period in 2013. Average realized natural gas prices increased 9% to $2.59 per Mcf in the third quarter of 2014 from $2.38 per Mcf in the same period in 2013. Average realized NGL prices decreased 5% to $28.46 per Bbl in the third quarter of 2014 from $29.83 per Bbl in the same period in 2013.

-23-


Lease operating expenses for the three months ended September 30, 2014 increased to $21.0 million ($6.80 per Boe) from $12.9 million ($4.68 per Boe) for the same period in 2013. The increase in lease operating expenses is primarily due to increased operating costs associated with increased production from new wells in the Eagle Ford, partially offset by the sale of Barnett to EnerVest. The increase in lease operating expense per Boe is primarily due to the sale of lower operating cost per Boe gas properties in the Barnett as well as increased production from higher operating cost per Boe oil properties in the Eagle Ford.
Production taxes increased to $8.4 million (4.3% of revenues) for the three months ended September 30, 2014 from $5.6 million (3.9% of revenues) for the same period in 2013 as a result of increased oil production, primarily in the Eagle Ford. The increase in production taxes as a percentage of revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.
Ad valorem taxes increased slightly to $2.2 million for the three months ended September 30, 2014 as compared to $2.1 million for the same period in 2013. The increase in ad valorem taxes is due to new wells drilled in Eagle Ford in 2013, partially offset by the sale of Barnett to EnerVest.
Depreciation, depletion and amortization (“DD&A”) expense for the third quarter of 2014 increased to $83.6 million ($27.05 per Boe) from $55.4 million ($20.05 per Boe) in the third quarter of 2013. The increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to the impact of the significant decrease in natural gas reserves in the Barnett as a result of the sale to EnerVest as well as the increase in crude oil reserves, primarily in the Eagle Ford, which have a higher finding cost per Boe than our natural gas reserves. The components of our DD&A expense were as follows:
 
 
 Three Months Ended
September 30,
 
 
2014
 
2013
 
 
(In thousands)
DD&A of proved oil and gas properties
 

$82,645

 

$54,541

Depreciation of other property and equipment
 
433

 
442

Amortization of other assets
 
293

 
251

Accretion of asset retirement obligations
 
201

 
128

Total DD&A
 

$83,572

 

$55,362

General and administrative expense decreased to $9.5 million for the three months ended September 30, 2014 from $19.7 million for the corresponding period in 2013. The decrease was primarily due to decreased stock-based compensation expense associated with SARs as a result of a decrease in stock price during the three months ended September 30, 2014 as compared to an increase in stock price during the corresponding period in 2013, partially offset by an increase in stock-based compensation expense associated with a higher level of restricted stock outstanding during third quarter of 2014 as compared to the same period of 2013.
The gain on derivative instruments, net for the three months ended September 30, 2014 amounted to $71.8 million primarily due to the downward shift in the futures curve of forecasted commodity prices for crude oil and natural gas from July 1, 2014 (or the subsequent date on which new contracts were entered into) to September 30, 2014. The loss on derivative instruments, net for the three months ended September 30, 2013 amounted to $27.7 million primarily due to the upward shift in the futures curve of forecasted commodity prices for crude oil from July 1, 2013 (or the subsequent date on which prior year contracts were entered into) to September 30, 2013.
Interest expense, net for the three months ended September 30, 2014 was $12.2 million as compared to $13.4 million for the same period in 2013. The decrease in interest expense, net was primarily due to an increase in the amount of interest that was capitalized due to a higher average balance of unproved properties.
The effective income tax rate for the third quarter of 2014 and 2013 was 36.4% and 24.6%, respectively. The rate for third quarter 2014 is higher than the U. S. federal statutory rate of 35% primarily due to the impact of state income tax, while the rate for the third quarter of 2013 is lower than the U. S. federal statutory rate of 35% due to a change in estimate for state income tax.

-24-


Nine Months Ended September 30, 2014, Compared to the Nine Months Ended September 30, 2013
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the nine months ended September 30, 2014 and 2013:
 
Nine Months Ended
September 30,
 
2014 Period
Compared to 2013 Period
 
2014
 
2013
 
Increase
(Decrease)
 
% Increase
(Decrease)
Total production volumes -
 
 
 
 
 
 
 
    Crude oil (MBbls)
4,870

 
3,032

 
1,838

 
61
%
    NGLs (MBbls)
648

 
408

 
240

 
59
%
    Natural gas (MMcf)
17,951

 
25,680

 
(7,729
)
 
(30
%)
        Total Natural gas and NGLs (MMcfe)
21,839

 
28,128

 
(6,289
)
 
(22
%)
Total barrels of oil equivalent (MBoe)
8,510

 
7,720

 
790

 
10
%
 
 
 
 
 
 
 
 
Daily production volumes by product -
 
 
 
 
 
 
 
    Crude oil (Bbls/d)
17,839

 
11,106

 
6,733

 
61
%
    NGLs (Bbls/d)
2,374

 
1,495

 
879

 
59
%
    Natural gas (Mcf/d)
65,755

 
94,066

 
(28,311
)
 
(30
%)
        Total Natural gas and NGLs (Mcfe/d)
79,996

 
103,033

 
(23,037
)
 
(22
%)
Total barrels of oil equivalent (Boe/d)
31,172

 
28,278

 
2,894

 
10
%
 
 
 
 
 
 
 
 
Daily production volumes by region (Boe/d) -
 
 
 
 
 
 
 
    Eagle Ford
19,753

 
12,184

 
7,569

 
62
%
    Niobrara
2,497

 
1,621

 
876

 
54
%
    Barnett

 
8,131

 
(8,131
)
 
(100
%)
    Marcellus
8,222

 
6,016

 
2,206

 
37
%
    Utica and other
700

 
326

 
374

 
115
%
Total barrels of oil equivalent (Boe/d)
31,172

 
28,278

 
2,894

 
10
%
 
 
 
 
 
 
 
 
Average realized prices -
 
 
 
 
 
 
 
    Crude oil ($ per Bbl)

$96.43

 

$102.60

 

($6.17
)
 
(6
%)
    NGLs ($ per Bbl)
30.35

 
28.26

 
2.09

 
7
%
    Natural gas ($ per Mcf)
3.21

 
2.64

 
0.57

 
22
%
        Total Natural gas and NGLs ($ per Mcfe)

$3.54

 

$2.82

 

$0.72

 
26
%
Total average realized price ($ per Boe)

$64.27

 

$50.58

 

$13.69

 
27
%
 
 
 
 
 
 
 
 
Revenues (In thousands) -
 
 
 
 
 
 
 
    Crude oil

$469,601

 

$311,084

 

$158,517

 
51
%
    NGLs
19,669

 
11,532

 
8,137

 
71
%
    Natural gas
57,642

 
67,838

 
(10,196
)
 
(15
%)
Total revenues

$546,912

 

$390,454

 

$156,458

 
40
%
Revenues for the nine months ended September 30, 2014 increased 40% to $546.9 million from $390.5 million for the same period in 2013 primarily due to the increase in oil production, partially offset by the decrease in gas production and oil prices. Production volumes for the nine months ended September 30, 2014 and 2013 were 8.5 MMBoe and 7.7 MMBoe, respectively. The increase in production from the nine months ended September 30, 2013 to the nine months ended September 30, 2014 was primarily due to increased production from new wells in the Eagle Ford and Marcellus, partially offset by normal production declines and the sale of Barnett to EnerVest. Average realized oil prices decreased 6% to $96.43 per barrel from $102.60 per barrel in the same period in 2013. Average realized gas prices increased 22% to $3.21 per Mcf for the nine months ended September 30, 2014 from $2.64 per Mcf in the same period in 2013. Average realized NGL prices increased 7% to $30.35 per Bbl for the nine months ended September 30, 2014 from $28.26 per Bbl in the same period in 2013.
Lease operating expenses were $51.0 million ($5.99 per Boe) for the nine months ended September 30, 2014 as compared to lease operating expenses of $34.9 million ($4.52 per Boe) for the same period in 2013. The $16.1 million increase in lease operating expenses is primarily due to increased operating costs associated with increased production from new wells in the Eagle

-25-


Ford, partially offset by the sale of Barnett to EnerVest. The increase in lease operating expense per Boe is primarily due to the sale of lower operating cost per Boe gas properties in the Barnett as well as increased production from higher operating cost per Boe oil properties in the Eagle Ford.
Production taxes were $22.7 million (or 4.1% of revenues) for the nine months ended September 30, 2014 as compared to $14.7 million (or 3.8% of revenues) for the same period in 2013. The increase in production taxes is due primarily to increased oil production, primarily in the Eagle Ford, partially offset by the sale of Barnett to EnerVest. The increase in production taxes as a percentage of revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.
Ad valorem taxes decreased to $5.6 million for the nine months ended September 30, 2014 from $6.8 million for the same period in 2013. The decrease in ad valorem taxes is due primarily to lower actual ad valorem taxes than previously estimated for the year ended December 31, 2013 and the sale of Barnett to EnerVest, partially offset by an increase in ad valorem taxes for new wells drilled in Eagle Ford in 2013.
DD&A expense for the nine months ended September 30, 2014 increased $77.3 million to $228.9 million ($26.90 per Boe) from the DD&A expense for the nine months ended September 30, 2013 of $151.6 million ($19.64 per Boe). The increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to the impact of the significant decrease in natural gas reserves in the Barnett as a result of the sale to EnerVest as well as the increase in crude oil reserves, primarily in the Eagle Ford, which have a higher finding cost per Boe than our natural gas reserves. The components of our DD&A expense were as follows:
 
 
Nine Months Ended
September 30,
 
 
2014
 
2013
 
 
(In thousands)
DD&A of proved oil and gas properties
 

$226,217

 

$149,294

Depreciation of other property and equipment
 
1,309

 
1,249

Amortization of other assets
 
894

 
689

Accretion of asset retirement obligations
 
492

 
355

Total DD&A
 

$228,912

 

$151,587

General and administrative expense increased to $65.5 million for the nine months ended September 30, 2014 from $53.7 million for the corresponding period in 2013. The increase was primarily due an increase in stock-based compensation expense as a result of a higher level of restricted stock outstanding during the nine months ended September 30, 2014 as compared to same period in 2013 as well as an increase in personnel for 2014 as compared to 2013.
The gain on derivative instruments, net for the nine months ended September 30, 2014 amounted to $11.2 million primarily due to new hedge additions during 2014 and the significant downward shift in the futures curve of forecasted commodity prices for crude oil and natural gas from July 1, 2014 (or the subsequent date prior year contracts were entered into) to September 30, 2014, partially offset by the upward shift in the commodity prices for crude oil from January 1, 2014 to June 30, 2014. The loss on derivative instruments, net for the nine months ended September 30, 2013 amounted to $16.5 million primarily due to the upward shift in the futures curve of forecasted commodity prices for crude oil from January 1, 2013 (or the subsequent date prior year contracts were entered into) to September 30, 2013.
Interest expense, net for the nine months ended September 30, 2014 was $36.6 million as compared to $42.4 million for the same period in 2013. The decrease in interest expense was primarily due to the repurchase of the 4.375% convertible senior notes in June 2013 as well as an increase in the amount of interest that was capitalized due to a higher average balance of unproved properties.
The effective income tax rates for the nine months ended September 30, 2014 and 2013 were 36.6% and 37.0%, respectively. These rates are higher than the U.S. federal statutory corporate income tax rate of 35% primarily due to the impact of state income taxes.

-26-


Liquidity and Capital Resources
2014 Capital Expenditure Plan and Funding Strategy. Our 2014 drilling and completion capital expenditure plan is $690.0 million to $710.0 million (excluding the recent Eagle Ford Shale Transaction). Our 2014 leasehold and seismic capital expenditure plan is $150.0 million. We expect to allocate the majority of the leasehold and seismic capital to acreage acquisitions in the Eagle Ford and Utica shales. We currently intend to finance the remainder of our 2014 capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. Below is a summary of capital expenditures through September 30, 2014:
 
Three Months Ended
 
Nine Months Ended
 
March 31, 2014
 
June 30, 2014
 
September 30, 2014
 
September 30, 2014
 
(In thousands)
Drilling and completion
 
 
 
 
 
 
 
Eagle Ford

$128,870

 

$154,350

 

$118,353

 

$401,573

Niobrara
24,204

 
29,726

 
27,430

 
81,360

Utica
2,238

 
4,396

 
10,094

 
16,728

Marcellus
13,736

 
9,931

 
(2,418
)
 
21,249

Other
1,649

 
(289
)
 
6,274

 
7,634

     Total drilling and completion
170,697

 
198,114

 
159,733

 
528,544

Leasehold and seismic
27,268

 
73,406

 
22,973

 
123,647

Total

$197,965

 

$271,520

 

$182,706

 

$652,191

Our capital expenditure plan and the capital expenditures included above exclude capitalized general and administrative expense, capitalized interest and asset retirement obligations.
Sources and Uses of Cash. Our primary use of cash is capital expenditures related to our drilling and completion programs and, to a lesser extent, our leasehold and seismic data acquisition programs. For the nine months ended September 30, 2014, we funded our capital expenditures with cash provided by operations, cash on hand, and borrowings under our revolving credit facility. Potential sources of future liquidity include the following:
Cash provided by operations. Cash flows from operations are highly dependent on commodity prices. As such, we hedge a portion of our forecasted production to mitigate the risk of a decline in oil and gas prices.
Borrowings under our revolving credit facility. At October 31, 2014, we had no borrowings outstanding and $0.6 million in letters of credit outstanding under the revolving credit facility, which reduce the amounts available under our revolving credit facility. The amount we are able to borrow with respect to the borrowing base of the revolving credit facility is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility. As a result of the Fall 2014 borrowing base redetermination and in conjunction with the acquisition of additional leasehold and producing interests in the Eagle Ford Shale Transaction, the borrowing base was increased to $800.0 million. However, we voluntarily elected to limit the lenders’ aggregate commitment to $685.0 million. The lenders’ aggregate commitment can be increased at any time to the full $800.0 million by requesting one or more lenders to approve an increase to their commitment.
Asset sales. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us.
Securities offerings. As situations or conditions arise, we may choose to issue debt, equity or other instruments to supplement our cash flows, including the recent issuance of $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.
Joint ventures. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both.
Lease purchase option arrangements. Lease option agreements and land banking arrangements, such as those we have previously entered into in other plays.
Other sources. We may consider sale/leaseback transactions of certain capital assets, such as our remaining pipelines and compressors, which are not part of our core oil and gas exploration and production business.

-27-


Overview of Cash Flow Activities. Net cash provided by operating activities from continuing operations was $388.7 million and $310.3 million for the nine months ended September 30, 2014 and 2013, respectively. The change was primarily due to increased crude oil revenues, offset by increases in operating expenses, net cash paid/received for derivative settlements, and the net change in working capital related to operating activities.
Net cash used in investing activities from continuing operations were $654.2 million and $503.4 million for the nine months ended September 30, 2014 and 2013, respectively and relate primarily to oil and gas capital expenditures associated with our capital expenditure plan.
Net cash provided by financing activities from continuing operations were $123.2 million and $17.4 million for the nine months ended September 30, 2014 and 2013, respectively. The increase was primarily due to increased net borrowings in 2014 as compared to 2013, consisting of increased borrowings under our revolving credit facility, as well as the repurchase of the 4.375% convertible senior notes in the second quarter of 2013.
Liquidity and Cash Flow Outlook
Economic downturns may adversely affect our ability to access capital markets in the future. We currently believe that cash provided by operating activities and borrowings under our revolving credit facility will be sufficient to fund our immediate cash flow requirements. Cash provided by operating activities is primarily driven by production and commodity prices. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows to support our drilling and completion capital expenditure program, we hedge a portion of our forecasted production and, as of September 30, 2014, our hedge positions for the remainder of 2014 comprised 54,380 MMBtu/d of natural gas and 15,000 Bbls/d of crude oil. As of October 31, 2014, our borrowing base under our revolving credit facility is $800.0 million, which was increased from $675.0 million in connection with the Eagle Ford Shale Transaction. In connection with such borrowing base increase, we elected to limit the aggregate principal amount of the commitments of the lenders under the credit agreement governing our revolving credit facility to $685.0 million. As of October 31, 2014, we had no borrowings outstanding under our revolving credit facility. Additionally, as described under “—Sources and Uses of Cash” above, the amount we are 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 borrowing base under our revolving credit facility is affected by our lenders’ assumptions with respect to future oil and gas prices. Our borrowing base may decrease if our lenders reduce their expectations with respect to future oil and gas prices from those assumptions used to determine our existing borrowing base. The next borrowing base redetermination is expected to occur in the Spring of 2015.
If cash provided by operating activities from continuing operations, borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund the remainder of our 2014 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2014 capital expenditure plan, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from asset sales, securities offerings or borrowings to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.

-28-


Contractual Obligations
The following table sets forth estimates of our contractual obligations as of September 30, 2014 (in thousands):
 
October-December 2014
 
2015
 
2016
 
2017
 
2018
 
2019 and Thereafter
 
Total
Long-term debt (1)

$—

 

$—

 

$—

 

$—

 

$719,000

 

$304,425

 

$1,023,425

Interest on long-term debt (2)
26,521

 
76,835

 
76,835

 
76,835

 
75,659

 
46,823

 
379,508

Operating leases
447

 
3,774

 
3,752

 
3,881

 
3,974

 
14,242

 
30,070

Drilling and completion services (3)
12,311

 
34,936

 
21,277

 
20,057

 
3,864

 

 
92,445

Pipeline volume commitments (3)
1,409

 
7,435

 
3,432

 
1,565

 
1,565

 
9,733

 
25,139

Asset retirement obligations and other (4)
2,099

 
9,026

 
6,806

 
2,870

 
803

 
10,059

 
31,663

Total Contractual Obligations

$42,787

 

$132,006

 

$112,102

 

$105,208

 

$804,865

 

$385,282

 

$1,582,250

 
(1)
Long-term debt consists of the principal amounts of the 8.625% Senior Notes due 2018, the 7.50% Senior Notes due 2020, other long-term debt due 2028 and $119.0 million of borrowings outstanding as of September 30, 2014 under our revolving credit facility which matures in 2018.
(2)
Cash payments for interest on the 8.625% Senior Notes due 2018, the 7.50% Senior Notes due 2020, other long-term debt due 2028 and our revolving credit facility which matures in 2018 are estimated assuming no principal repayments until the due dates of the instruments. Cash interest payments on our revolving credit facility were calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of September 30, 2014 of 2.01%.
(3)
Drilling and completion services and pipeline volume commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs.
(4)
Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of September 30, 2014. Certain of such estimates and assumptions are inherently unpredictable and will differ from actuals results. See Note 2. Summary of Significant Accounting Policies - Use of Estimates for further discussion of estimates and assumptions that may affect the reported amounts.
Financing Arrangements
7.50% Senior Notes
As described under “—Recent Developments”, on October 30, 2014, we completed an offering of $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020 at a price equal to 100.50% of par, plus accrued interest from September 15, 2014.
8.625% Senior Notes
As of September 30, 2014, we had $600.0 million aggregate principal amount of 8.625% Senior Notes due 2018 issued and outstanding. The 8.625% Senior Notes are guaranteed by all of our existing Material Domestic Subsidiaries (as defined in the credit agreement governing our revolving credit facility). The 8.625% Senior Notes mature on October 15, 2018, with interest payable semi-annually. Since October 15, 2014, we had the right to redeem all or a portion of our 8.625% Senior Notes at redemption prices decreasing from 104.313% to 100% of the principal amount on October 15, 2017, plus accrued and unpaid interest. We could seek to refinance the 8.625% Senior Notes in connection with such a redemption or a repurchase of notes.
Senior Secured Revolving Credit Facility
We are party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the administrative agent. The revolving credit facility is secured by substantially all of our U.S. assets and is guaranteed by all of our existing Material Domestic Subsidiaries (as defined in the credit agreement governing the revolving credit facility). Any subsidiary of ours that does not currently guarantee our obligations under our revolving credit facility that subsequently becomes a Material Domestic Subsidiary will be required to guarantee our obligations under our revolving credit facility.
On October 7, 2014, a fifth amendment to the credit agreement governing our revolving credit facility (the “Fifth Amendment”) was executed. The Fifth Amendment (i) permitted us to increase or decrease the aggregate principal amount of the commitments of the lenders under the credit agreement governing the revolving credit facility provided that the aggregate commitments do not exceed the then existing borrowing base, (ii) increased the letter of credit sublimit under such facility from $15.0 million to $30.0 million, (iii) established an approved borrowing base of $675.0 million until the next redetermination and (iv) amended the availability of issuances of additional senior notes. As a result of the Fall 2014 borrowing base redetermination, effective October 7, 2014, the borrowing base was increased to $675.0 million from $570.0 million. Prior to giving effect to the amendment, the senior secured revolving credit facility provided availability for issuances of additional senior notes in the aggregate principal amount of up to $350.0 million. The amendment replaced this limitation to permit unlimited issuances of additional senior notes

-29-


as long as, subject to certain other conditions described therein, after giving effect to the issuance of the additional senior notes, we are in compliance with our financial covenants under the credit agreement governing our revolving credit facility.
In conjunction with the Eagle Ford Shale Transaction completed on October 24, 2014, the borrowing base was increased to $800.0 million from $675.0 million. However, we voluntarily elected to limit the lenders’ aggregate commitment to $685.0 million. The lenders’ aggregate commitment can be increased at any time to the full $800.0 million by requesting one or more lenders to approve an increase to their commitment. The borrowing base will be redetermined by the lenders at least semi-annually on or around each May 1 and November 1, with the next redetermination expected in Spring 2015. The amount we are 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.
We are subject to certain covenants under the terms of the revolving credit facility, as amended, which include, but are not limited to, the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00 (each of the capitalized terms used in the foregoing clauses (1) and (2) being as defined in the credit agreement governing the revolving credit facility). As of September 30, 2014, the ratio of Total Debt to EBITDA was 2.02 to 1.00 and the Current Ratio was 1.68 to 1.00. As defined in the credit agreement governing the revolving credit facility, Total Debt is net of cash and cash equivalents and the Current Ratio includes an add back of the available borrowing capacity.
Our revolving credit facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
Our revolving credit facility is subject to customary events of default, including a change in control (as defined in the credit agreement governing our revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the credit agreement governing our revolving credit facility) may accelerate amounts due under the revolving credit facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).
As of September 30, 2014, we had $119.0 million of borrowings outstanding under the revolving credit facility and had $0.6 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. The amount we are 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 revolving credit facility is generally used to fund ongoing working capital needs and the remainder of our capital expenditure plan to the extent such amounts exceed the cash flows from operations and proceeds from asset sales and securities offerings.
Critical Accounting Policies
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 financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, income taxes and commitments and contingencies. These policies and estimates are described in our Annual Report on Form 10-K for the year ended December 31, 2013. We evaluate subsequent events through the date the financial statements are issued.

-30-


The table below presents results of the full cost ceiling test as of September 30, 2014 along with various pricing scenarios to demonstrate the sensitivity of our cost center ceiling to changes in 12 month average benchmark oil and gas prices underlying our average realized prices. Prices do not include the impact of crude oil and natural gas derivative instruments. This sensitivity analysis is as of September 30, 2014, and, accordingly, does not consider drilling results, production and prices subsequent to September 30, 2014 that may require revisions to our proved reserve estimates.
 
 
12 Month Average Realized Prices
 
Excess of cost center ceiling over net capitalized costs
 
Increase (Decrease) in excess of cost center ceiling over net capitalized costs
Full Cost Pool Scenarios
 
Crude Oil ($/Bbl)
 
Natural Gas ($/Mcf)
 
 (In millions)
 
(In millions)
September 30, 2014 Actual
 
$96.80
 
$3.31
 
$520
 
 
 
 
 
 
 
 
 
 
 
Oil and Gas Price Sensitivity
 
 
 
 
 
 
 
 
Oil and Gas +10%
 
$106.70
 
$3.74
 
$797
 
$277
Oil and Gas -10%
 
$86.90
 
$2.88
 
$243
 
($277)
 
 
 
 
 
 
 
 
 
Oil Price Sensitivity
 
 
 
 
 
 
 
 
Oil +10%
 
$106.70
 
$3.31
 
$769
 
$249
Oil -10%
 
$86.90
 
$3.31
 
$271
 
($249)
 
 
 
 
 
 
 
 
 
Gas Price Sensitivity
 
 
 
 
 
 
 
 
Gas +10%
 
$96.80
 
$3.74
 
$548
 
$28
Gas -10%
 
$96.80
 
$2.88
 
$492
 
($28)
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry specific guidance in Subtopic 932-605, Extractive Activities- Oil and Gas- Revenue Recognition. This ASU requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. This ASU is effective for annual and interim periods beginning in 2017, and is required to be adopted either retrospectively or as an accumulative-effect adjustment as of the date of adoption, with no early adoption permitted. We are currently evaluating the impact of the adoption of this ASU on our consolidated financial statements.
Volatility of Oil and Gas Prices
Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of oil and gas.
We review the carrying value of our oil and gas properties on a quarterly basis using the full cost method of accounting. See “Summary of Critical Accounting Policies—Oil and Gas Properties,” in our Annual Report on Form 10-K for the year ended December 31, 2013.
We use commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce our exposure to commodity price volatility for a substantial, but varying, portion of our forecasted oil and gas production up to 36 months and thereby achieve a more predictable level of cash flows to support our drilling and completion capital expenditure program. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We do not enter into derivative instruments for speculative or trading purposes.

-31-


We typically have numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. We net our derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value of derivative instruments where we are in a net asset position with our counterparties as of September 30, 2014 and December 31, 2013 totaled $36.0 million and $9.3 million, respectively, and is summarized by counterparty in the table below:
Counterparty
 
September 30, 2014
 
December 31, 2013
Wells Fargo
 
41
%
 
23
%
Credit Suisse
 
23
%
 
46
%
Societe Generale
 
22
%
 
31
%
Regions
 
8
%
 
%
Union Bank
 
4
%
 
%
Royal Bank of Canada
 
2
%
 
%
Total
 
100
%
 
100
%
The counterparties to our derivative instruments are lenders under our credit agreement. Because each of the lenders have investment grade credit ratings, we believe we have minimal credit risk and accordingly do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, we are exposed to credit risk to the extent of nonperformance by the counterparties to our derivative instruments. Although we do not currently anticipate such nonperformance, we continue to monitor the financial viability of our counterparties.
The fair value of derivative instruments where we are in a net liability position with our counterparties as of September 30, 2014 and December 31, 2013 totaled $0.2 million and $10.1 million, respectively.
For the three months ended September 30, 2014 and 2013, we recorded in the consolidated statements of income a gain on derivative instruments, net of $71.8 million and a loss on derivative instruments, net of $27.7 million, respectively. For the nine months ended September 30, 2014 and 2013, we recorded in the consolidated statements of income a gain on derivative instruments, net of $11.2 million and a loss on derivative instruments, net of $16.5 million, respectively.
The following sets forth a summary of our crude oil derivative positions at average NYMEX prices as of September 30, 2014:
Period    
 
Type of Contract
 
Volumes
(in Bbls/d)
 
Weighted
Average
Floor Price
($/Bbl)
 
Weighted
Average
Ceiling Price
($/Bbl)
 
Weighted
Average
Short Put  Price
($/Bbl)
 
Weighted
Average
Put Spread
($/Bbl)
October - December 2014
 
Fixed Price Swaps
 
11,500

 

$93.55

 


 
 
 
 
 
 
Costless Collars
 
3,000

 

$88.33

 

$104.26

 
 
 
 
 
 
Three-way Collars
 
500

 

$85.00

 

$107.75

 

$65.00

 

$20.00

January - December 2015
 
Fixed Price Swaps
 
10,370

 

$92.97

 


 
 
 
 
 
 
Costless Collars
 
700

 

$90.00

 

$100.65

 
 
 
 
 
 
Three-way Collars
 
1,000

 

$85.00

 

$105.00

 

$65.00

 

$20.00

January - December 2016
 
Fixed Price Swaps
 
3,000

 

$91.09

 
 
 
 
 
 
 
 
Three-way Collars
 
667

 

$85.00

 

$104.00

 

$65.00

 

$20.00

The following sets forth a summary of our natural gas derivative positions at average NYMEX prices as of September 30, 2014:
Period    
 
Type of Contract
 
Volumes
(in MMBtu/d)
 
Weighted
Average
Floor Price
($/MMBtu)
 
Weighted
Average
Ceiling Price
($/MMBtu)
October - December 2014
 
Fixed Price Swaps
 
54,380

 

$4.16

 


 
 
Calls
 
10,000

 


 

$5.50

January - December 2015
 
Fixed Price Swaps
 
30,000

 

$4.29

 



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Forward-Looking Statements
The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, timing and amounts of production, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, pipeline connections, increases in reserves, acreage, working capital requirements, commodity price risk management activities and the impact on our average realized prices, the availability of expected sources of liquidity to implement the Company’s business strategies, accessibility of borrowings under our credit facility, debt repayments, redemptions or tender offers, future exploration activity, drilling, completion and fracturing of wells, land acquisitions, production rates, forecasted production, growth in production, development of new drilling programs, participation of our industry partners, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, availability of and results of new and existing joint ventures and sales transactions, receipt of receivables, proceeds from sales, use of proceeds and all and any other statements regarding future operations, financial results, business plans and cash needs and other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “plan,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, actions and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under our credit facility, evaluations of the Company by lenders under our credit facility the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information, property acquisition risks, availability of equipment, actions by our midstream and other industry partners, weather, availability of financing, market conditions, actions by lenders, our ability to obtain permits and licenses, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability of and completion of land acquisitions, completion and connection of wells, and other factors detailed in the “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the year ended December 31, 2013 and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material changes to the disclosure regarding our exposure to certain market risks made in our Annual Report on Form 10-K for the year ended December 31, 2013.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of September 30, 2014 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

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Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended September 30, 2014 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
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 materially adverse effect on the financial position or results of operations of the Company.
Please see our Current Report on Form 8-K filed on September 26, 2014 for information on a jury verdict against the Company on September 24, 2014 in a case entitled Barrow-Shaver Resources Company v. Carrizo Oil & Gas, Inc. in the 7th Judicial District Court of Smith County, Texas.
Item 1A. Risk Factors
There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
The Eagle Ford Shale Transaction. On October 24, 2014, we completed the acquisition of additional leasehold and producing interests in the Eagle Ford Shale (the “Eagle Ford Shale Transaction”) from Eagle Ford Minerals, LLC (“EFM”). For a further description of this matter, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments.” We reported the consummation of the Eagle Ford Shale Transaction on October 27, 2014 on a Current Report on Form 8-K filed on that date. Historical financial statements for the business acquired and pro forma financial information were not included in that report but will be filed in a subsequent Current Report on Form 8-K within the time period set forth in the Securities Exchange Act of 1934 and rules promulgated thereunder.
Item 6. Exhibits
The following exhibits are required by Item 601 of Regulation S-K and are filed as part of this report: 
Exhibit
Number
  
Exhibit Description
2.1
Asset Purchase Agreement dated October 24, 2014 by and between Eagle Ford Minerals, LLC and Carrizo (Eagle Ford) LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 27, 2014). The schedules to the Asset Purchase Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.
*10.1
Retirement and Consulting Agreement effective as of August 11, 2014 by and between Carrizo Oil & Gas, Inc. and Paul F. Boling.
*31.1
CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2
CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1
CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2
CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101
Interactive Data Files
 
* Filed herewith.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
Carrizo Oil & Gas, Inc.
(Registrant)
 
 
 
 
 
Date:
November 6, 2014
 
By:
/s/ David L. Pitts
 
 
 
 
Vice President and Chief Financial Officer
(Principal Financial Officer)
 
 
 
 
Date:
November 6, 2014
 
By:
/s/ Gregory F. Conaway
 
 
 
 
Vice President and Chief Accounting Officer
(Principal Accounting Officer)

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