Carrizo Oil and Gas, Inc.
CARRIZO OIL & GAS INC (Form: 10-Q, Received: 05/09/2017 16:46:11)


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 March 31, 2017
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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
 
¨
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ¨  
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 April 28, 2017 was 65,807,064 .






TABLE OF CONTENTS
 
PAGE
Part I. Financial Information
 
Item 1.
 
 
 
 
 
Item 2.
Item 3.
Item 4.
Part II. Other Information
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Signatures



Part I. Financial Information
Item 1. Consolidated Financial Statements (Unaudited)
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
(Unaudited)
 
 
March 31,
2017
 
December 31,
2016
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 

$2,391

 

$4,194

Accounts receivable, net
 
67,257

 
64,208

Derivative assets
 
1,036

 
1,237

Other current assets
 
2,542

 
3,349

Total current assets
 
73,226

 
72,988

Property and equipment
 
 
 
 
Oil and gas properties, full cost method
 
 
 
 
Proved properties, net
 
1,371,335

 
1,294,667

Unproved properties, not being amortized
 
253,270

 
240,961

Other property and equipment, net
 
9,599

 
10,132

Total property and equipment, net
 
1,634,204

 
1,545,760

Other assets
 
7,010

 
7,579

Total Assets
 

$1,714,440

 

$1,626,327

 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 

$51,968

 

$55,631

Revenues and royalties payable
 
44,038

 
38,107

Accrued capital expenditures
 
69,040

 
36,594

Accrued interest
 
20,957

 
22,016

Accrued lease operating expense
 
11,919

 
12,377

Derivative liabilities
 
7,456

 
22,601

Other current liabilities
 
22,650

 
24,633

Total current liabilities
 
228,028

 
211,959

Long-term debt
 
1,362,046

 
1,325,418

Asset retirement obligations
 
21,737

 
20,848

Derivative liabilities
 
18,675

 
27,528

Other liabilities
 
14,027

 
17,116

Total liabilities
 
1,644,513

 
1,602,869

Commitments and contingencies
 

 

Shareholders’ equity
 
 
 
 
Common stock, $0.01 par value, 90,000,000 shares authorized; 65,796,342 issued and outstanding as of March 31, 2017 and 65,132,499 issued and outstanding as of December 31, 2016
 
658

 
651

Additional paid-in capital
 
1,672,332

 
1,665,891

Accumulated deficit
 
(1,603,063
)
 
(1,643,084
)
Total shareholders’ equity
 
69,927

 
23,458

Total Liabilities and Shareholders’ Equity
 

$1,714,440

 

$1,626,327

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

- 2 -


CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
 
 Three Months Ended
March 31,
 
2017
 
2016
Revenues
 
 
 
Crude oil

$128,092

 

$67,996

Natural gas liquids
7,425

 
3,440

Natural gas
15,838

 
9,826

Total revenues
151,355

 
81,262

 
 
 
 
Costs and Expenses
 
 
 
Lease operating
29,845

 
23,675

Production taxes
6,208

 
3,431

Ad valorem taxes
2,967

 
2,070

Depreciation, depletion and amortization
54,382

 
59,577

General and administrative, net
21,703

 
21,303

(Gain) loss on derivatives, net
(25,316
)
 
(10,553
)
Interest expense, net
20,571

 
18,713

Impairment of proved oil and gas properties

 
274,413

Other (income) expense, net
974

 
(93
)
Total costs and expenses
111,334

 
392,536

 
 
 
 
Income (Loss) Before Income Taxes
40,021

 
(311,274
)
Income tax expense

 
(121
)
Net Income (Loss)

$40,021

 

($311,395
)
 
 
 
 
Net Income (Loss) Per Common Share
 
 
 
Basic

$0.61

 

($5.34
)
Diluted

$0.61

 

($5.34
)
 
 
 
 
Weighted Average Common Shares Outstanding
 
 
 
Basic
65,188

 
58,360

Diluted
65,778

 
58,360

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

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CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In thousands, except share amounts)
(Unaudited)
 
 
Common Stock
 
Additional
Paid-in
Capital
 

Accumulated Deficit
 
Total
Shareholders’
Equity
 
 
Shares
 
Amount
 
 
 
Balance as of December 31, 2016
 
65,132,499

 

$651

 

$1,665,891

 

($1,643,084
)
 

$23,458

Stock-based compensation expense
 

 

 
6,448

 

 
6,448

Issuance of common stock upon grants of restricted stock awards, net of forfeitures, and vestings of restricted stock units and performance shares
 
663,843

 
7

 
(7
)
 

 

Net income
 

 

 

 
40,021

 
40,021

Balance as of March 31, 2017
 
65,796,342

 

$658

 

$1,672,332

 

($1,603,063
)
 

$69,927

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


- 4 -


CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
Three Months Ended
March 31,
 
2017
 
2016
Cash Flows From Operating Activities
 
 
 
Net income (loss)

$40,021

 

($311,395
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 
 
 
Depreciation, depletion and amortization
54,382

 
59,577

Impairment of proved oil and gas properties

 
274,413

(Gain) loss on derivatives, net
(25,316
)
 
(10,553
)
Cash received for derivative settlements, net
1,519

 
51,163

Stock-based compensation expense, net
2,014

 
11,522

Non-cash interest expense, net
1,091

 
1,160

Other, net
1,620

 
1,116

Changes in components of working capital and other assets and liabilities-
 
 
 
Accounts receivable
(2,749
)
 
(2,065
)
Accounts payable
6,661

 
(18,711
)
Accrued liabilities
(2,154
)
 
(1,667
)
Other assets and liabilities, net
(681
)
 
(692
)
Net cash provided by operating activities
76,408

 
53,868

Cash Flows From Investing Activities
 
 
 
Capital expenditures - oil and gas properties
(123,749
)
 
(125,989
)
Acquisitions of oil and gas properties
(7,032
)
 

Proceeds from sales of oil and gas properties, net
17,372

 
1,785

Other, net
(417
)
 
(617
)
Net cash used in investing activities
(113,826
)
 
(124,821
)
Cash Flows From Financing Activities
 
 
 
Borrowings under credit agreement
280,504

 
73,647

Repayments of borrowings under credit agreement
(244,504
)
 
(43,097
)
Payments of debt issuance costs
(50
)
 
(50
)
Other, net
(335
)
 
(307
)
Net cash provided by financing activities
35,615

 
30,193

Net Decrease in Cash and Cash Equivalents
(1,803
)
 
(40,760
)
Cash and Cash Equivalents, Beginning of Period
4,194

 
42,918

Cash and Cash Equivalents, End of Period

$2,391

 

$2,158

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

- 5 -


CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of Presentation
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, NGLs, 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 Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania.
Consolidated Financial Statements
The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”) and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. These financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“ 2016 Annual Report”). 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.
2. Summary of Significant Accounting Policies
The Company has provided a discussion of significant accounting policies, estimates, and judgments in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2016 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2016 , other than the adoption of Accounting Standards Update No. 2016-09 described further below.
Recently Adopted Accounting Pronouncement
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.
Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. As a result of adoption, on a prospective basis as prescribed by ASU 2016-09, all windfall tax benefits and tax shortfalls will be recorded as income tax expense or benefit in the consolidated statements of operations. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, this portion of ASU 2016-09 will have no significant effect on the Company’s consolidated balance sheets or consolidated statements of operations. In addition, windfall tax benefits are now required to be presented in cash flows from operating activities in the consolidated statements of cash flows as compared to cash flows from financing activities, which the Company has elected to adopt prospectively. There are no periods presented that would require reclassification of cash flows had the Company elected to adopt this guidance retrospectively. Further, the Company has elected to account for forfeitures as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.
Recently Issued Accounting Pronouncements
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017,

- 6 -


with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently, the Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. Although the Company is in the process of evaluating ASU 2016-02 and the impact the adoption of the new standard will have on its consolidated financial statements and related disclosures, it is currently anticipated to result in an increase in the assets and liabilities recorded on its consolidated balance sheets. The Company will evaluate its existing contracts including, but not limited to, drilling rig contracts and gathering, processing, and transportation contracts to determine if they qualify for lease accounting under ASU 2016-02.
In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, timing, amount and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for interim and annual periods beginning after December 31, 2016. Companies are permitted to adopt ASU 2014-09 through the use of either the full retrospective approach, meaning the standard is applied to all of the periods presented, or a modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.
The Company is in the process of assessing the impact of ASU 2014-09 with the assistance of an outside consultant. The assessment consists of analyzing the Company’s existing contracts and current accounting policies and practices to identify potential differences that would result from applying the requirements of ASU 2014-09. Once the assessment is complete, the Company will implement appropriate changes to its business processes, systems or controls to support recognition and disclosure pursuant to ASU 2014-09. Based on assessments performed to date, the Company currently does not expect the impact of adopting ASU 2014-09 to have a material effect on the timing or method of revenue recognition as the performance obligations are not materially changed under ASU 2014-09. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018, however, the Company continues to review the impact of ASU 2014-09 on its consolidated financial statements and related disclosures.
Net Income (Loss) Per Common Share
Supplemental net income (loss) per common share information is provided below:
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands, except per share amounts)
Net Income (Loss)
 

$40,021

 

($311,395
)
Basic weighted average common shares outstanding
 
65,188

 
58,360

Effect of dilutive instruments
 
590

 

Diluted weighted average common shares outstanding
 
65,778

 
58,360

Net Income (Loss) Per Common Share
 
 
 
 
Basic
 

$0.61

 

($5.34
)
Diluted
 

$0.61

 

($5.34
)

- 7 -


The table below presents the dilutive and anti-dilutive weighted average common shares outstanding for the three months ended March 31, 2017 and 2016 :
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands)
Dilutive
 
590

 

Anti-dilutive (1)
 
5

 
665

 
(1)
For the three months ended March 31, 2016 , the Company reported a net loss. As a result, all potentially dilutive common shares outstanding were anti-dilutive.
3. Acquisition
Sanchez Acquisition
On December 14, 2016, the Company completed its initial closing of the acquisition of oil and gas properties in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation (the “Sanchez Acquisition”). The Sanchez Acquisition was accounted for under the acquisition method of accounting whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information.
At the time of the initial close, an adjustment to the purchase price of $16.8 million was made for leases that were not conveyed to the Company. On January 9, 2017, the Company paid $7.0 million of the $16.8 million for certain of the outstanding leases which were conveyed to the Company. See the updated purchase price allocation presented below.
The purchase price allocation for the Sanchez Acquisition is preliminary and subject to change based on closings subsequent to March 31, 2017, related to the remaining leases that were not conveyed to the Company at the initial closing on December 14, 2016 or the subsequent closing on January 9, 2017 and final updates to purchase price adjustments primarily relate to net cash flows from the acquired wells from the effective date to the closing date. The following presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. The Company currently expects these amounts will be finalized during the fourth quarter of 2017.
 
 
Preliminary Purchase Price Allocation
 
 
(In thousands)
Assets
 
 
Other current assets
 

$477

Oil and gas properties
 
 
Proved properties
 
94,664

Unproved properties
 
70,309

Total oil and gas properties
 
164,973

Total assets acquired
 

$165,450

 
 
 
Liabilities
 
 
Revenues and royalties payable
 

$1,442

Other current liabilities
 
323

Asset retirement obligations
 
2,054

Other liabilities
 
1,078

Total liabilities assumed
 

$4,897

Net Assets Acquired
 

$160,553

On April 13, 2017, the final payment of $9.8 million was made for the leases that were not conveyed to the Company at the initial closing or the subsequent closing on January 9, 2017. This amount has not been reflected in the preliminary purchase price allocation presented above.

- 8 -


4. Property and Equipment, Net
As of March 31, 2017 and December 31, 2016 , total property and equipment, net consisted of the following:
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands)
Oil and gas properties, full cost method
 
 
 
 
Proved properties
 

$4,817,044

 

$4,687,416

Accumulated depreciation, depletion and amortization and impairments
 
(3,445,709
)
 
(3,392,749
)
Proved properties, net
 
1,371,335

 
1,294,667

Unproved properties, not being amortized
 
 
 
 
Unevaluated leasehold and seismic costs
 
221,039

 
211,067

Capitalized interest
 
32,231

 
29,894

Total unproved properties, not being amortized
 
253,270

 
240,961

Other property and equipment
 
23,240

 
23,127

Accumulated depreciation
 
(13,641
)
 
(12,995
)
Other property and equipment, net
 
9,599

 
10,132

Total property and equipment, net
 

$1,634,204

 

$1,545,760

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $12.69 and $15.22 for the three months ended March 31, 2017 and 2016 , respectively.
The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $5.4 million and $4.4 million for the three months ended March 31, 2017 and 2016 , respectively.
Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling $3.8 million and $5.6 million for the three months ended March 31, 2017 and 2016 , respectively.
Divestiture
During the first quarter of 2017, the Company sold a small acreage position in the Delaware Basin for net proceeds of $15.3 million . The proceeds from this sale were recognized as a reduction of proved oil and gas properties.
Impairment of Proved Oil and Gas Properties
At the end of each quarter, the net book value of oil and gas properties, less 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. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current period (“12-Month Average Realized Price”), held flat for the life of the production, 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 as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

- 9 -


The Company did not recognize an impairment of proved oil and gas properties for the three months ended March 31, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil from December 31, 2015 to March 31, 2016, the Company recognized an impairment of proved oil and gas properties for the three months ended March 31, 2016 . Details of the 12-Month Average Realized Price of crude oil for the three months ended March 31, 2017 and 2016 and the impairment of proved oil and gas properties for the three months ended March 31, 2016 are summarized in the table below: 
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
Impairment of proved oil and gas properties (in thousands)
 

$—

 
$274,413
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period
 
$39.60
 
$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period
 
$44.98
 
$43.13
Percentage increase (decrease)
 
14
%
 
(9
%)
5. Income Taxes
The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense or benefit to interim periods. The rates are the ratio of estimated annual income tax expense or benefit to estimated annual income or loss 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 or loss before income taxes by taxing jurisdiction to determine the income tax expense or benefit allocated to the interim period. The Company updates its estimated annual effective income tax rates on a quarterly basis considering the geographic mix of income or loss attributable to the tax jurisdictions in which the Company operates.
The Company’s income tax (expense) benefit differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) before income taxes as follows:
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands)
Income (loss) before income taxes
 

$40,021

 

($311,274
)
Income tax (expense) benefit at the statutory rate
 
(14,007
)
 
108,946

State income tax (expense) benefit, net of U.S. federal income taxes
 
(710
)
 
1,619

Tax shortfalls from stock-based compensation expense
 
(2,592
)
 

Deferred tax assets valuation allowance
 
17,369

 
(110,679
)
Other
 
(60
)
 
(7
)
Income tax expense
 

$—

 

($121
)
Deferred Tax Assets Valuation Allowance
Deferred tax assets are recorded for net operating losses and temporary differences between the book and tax basis of assets and
liabilities expected to produce tax deductions in future periods. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.
A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at March 31, 2017 , driven primarily by the impairments of proved oil and gas properties recognized beginning
in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015, and continuing through the first quarter of 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including March 31, 2017 , were reduced to zero . As a result of adopting ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017. For the three months

- 10 -


ended March 31, 2017, as a result of current quarter activity and the recognition of tax shortfalls from stock-based compensation expense that are now recognized in income tax expense due to the adoption of ASU 2016-09, a partial release of $17.4 million from the valuation allowance was needed to bring the net deferred tax assets to zero. After the impact of the adoption of ASU 2016-09 and the current quarter activity, the valuation allowance as of March 31, 2017 was $562.7 million .
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
6. Long-Term Debt
Long-term debt consisted of the following as of March 31, 2017 and December 31, 2016 :
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands)
Senior Secured Revolving Credit Facility due 2018
 

$123,000

 

$87,000

7.50% Senior Notes due 2020
 
600,000

 
600,000

Unamortized premium for 7.50% Senior Notes
 
960

 
1,020

Unamortized debt issuance costs for 7.50% Senior Notes
 
(7,189
)
 
(7,573
)
6.25% Senior Notes due 2023
 
650,000

 
650,000

Unamortized debt issuance costs for 6.25% Senior Notes
 
(9,150
)
 
(9,454
)
Other long-term debt due 2028
 
4,425

 
4,425

Long-term debt
 

$1,362,046

 

$1,325,418

Senior Secured Revolving Credit Facility
The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2017 , had a borrowing base of $600.0 million , with $123.0 million of borrowings outstanding at a weighted average interest rate of 2.95% . As of March 31, 2017 , the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. As of March 31, 2017, the credit agreement governing the revolving credit facility provided for interest-only payments until July 2, 2018, when the credit agreement was scheduled to mature and any outstanding borrowings would become due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. 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. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.
The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00% , or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates, as of March 31, 2017, as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations.
Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments
 
Applicable Margin for
Base Rate Loans
 
Applicable Margin for
Eurodollar Loans
 
Commitment Fee
Less than 25%
 
1.00%
 
2.00%
 
0.500%
Greater than or equal to 25% but less than 50%
 
1.25%
 
2.25%
 
0.500%
Greater than or equal to 50% but less than 75%
 
1.50%
 
2.50%
 
0.500%
Greater than or equal to 75% but less than 90%
 
1.75%
 
2.75%
 
0.500%
Greater than or equal to 90%
 
2.00%
 
3.00%
 
0.500%

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As of March 31, 2017, the Company was subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Secured Debt to EBITDA of not more than 2.00 to 1.00, (2) a Current Ratio of not less than 1.00 to 1.00, and (3) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00. As defined in the credit agreement, EBITDA includes the last four quarters after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, Interest Expense is comprised of the aggregate interest expense paid in cash for the last four quarters, and the Current Ratio includes an add back of the unused portion of lender commitments. As of March 31, 2017 , the ratio of Total Secured Debt to EBITDA was 0.30 to 1.00, the Current Ratio was 2.56 to 1.00 and the ratio of EBITDA to Interest Expense was 4.53 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and dispositions of oil and gas properties and securities offerings.
The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
On May 4, 2017, the Company entered into a ninth amendment to its credit agreement governing the revolving credit facility. See “Note 13. Subsequent Events” for further details.
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. Shareholders’ Equity and Stock-Based Compensation Plans
As of March 31, 2017 , there were 26,275 common shares remaining available for grant under the Incentive Plan of Carrizo Oil & Gas, Inc., as amended (the “Incentive Plan”). The issuance of a restricted stock award, restricted stock unit, or performance share counts as 1.35 shares against the number of common shares available for grant under the Incentive Plan.
Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance shares is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties.
Restricted Stock Awards and Units. Under the Incentive Plan, restricted stock awards can be granted to employees and independent contractors and restricted stock units can be granted to employees, independent contractors, and non-employee directors. As of March 31, 2017 , unrecognized compensation costs related to unvested restricted stock awards and units was $31.4 million and will be recognized over a weighted average period of 2.4 years.
The table below summarizes restricted stock award and unit activity for the first quarter of 2017:
 
 
Restricted Stock Awards and Units
 
Weighted Average Grant Date
Fair Value
For the Three Months Ended March 31, 2017
 
 
 
 
Unvested restricted stock awards and units, beginning of period
 
1,111,710

 

$36.93

Granted
 
749,396

 

$27.07

Vested
 
(569,145
)
 

$39.48

Forfeited
 
(3,933
)
 

$29.42

Unvested restricted stock awards and units, end of period
 
1,288,028

 

$30.09

During the first quarter of 2017, the Company granted 695,658 restricted stock units to employees and independent contractors with a grant date fair value of $18.8 million as part of its annual grant of long-term equity incentive awards. These restricted stock

- 12 -


units will vest ratably over a three -year period. All of these restricted stock units contain a service condition, and certain of these restricted stock units also contain a performance condition. The performance condition has not yet been met. In addition, the Company granted 44,465 restricted stock units to certain employees and independent contractors with a grant date fair value of $1.2 million in lieu of a portion of their annual incentive bonus otherwise payable to them in cash under the Company’s performance-based annual incentive bonus program. These restricted stock units vested substantially concurrent with the time of grant.
Stock Appreciation Rights. SARs can be granted to employees and independent contractors under the Incentive Plan or the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). SARs granted under the Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. As of March 31, 2017 , all outstanding SARs will be settled solely in cash. The liability for SARs as of March 31, 2017 was $6.4 million , of which $6.3 million was classified as “Other current liabilities,” with the remaining $0.1 million classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016 , the liability for SARs was $11.5 million , of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $5.9 million as of March 31, 2017 , and will be recognized over a weighted average period of 1.8 years.
The table below summarizes the activity for SARs for the first quarter of 2017:
 
 
Stock Appreciation Rights
 
Weighted
Average
Exercise
Prices
 
Weighted Average Remaining Life
(In years)
 
Aggregate Intrinsic Value
(In millions)
 
Aggregate Intrinsic Value of Exercises
(In millions)
For the Three Months Ended March 31, 2017
 
 
 
 
 
 
 
 
 
 
Outstanding, beginning of period
 
722,638

 

$23.69

 
 
 
 
 
 
Granted
 
342,440

 

$26.94

 
 
 
 
 
 
Exercised
 
(100,000
)
 

$17.28

 
 
 
 
 

$1.3

Forfeited
 

 

 
 
 
 
 
 
Outstanding, end of period
 
965,078

 

$25.51

 
3.4
 

$2.5

 
 
Exercisable, end of period
 
436,739

 

$23.62

 
1.8
 

$2.0

 
 
During the first quarter of 2017, the Company granted 342,440 SARs under the Cash SAR Plan with a grant date fair value of $4.1 million to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. The grant date fair value of the SARs was calculated using the Black-Scholes-Merton option pricing model. These SARs will vest ratably over a two -year period and expire five years from the grant date. All of these SARs contain a service condition and performance condition. The performance condition has not yet been met.
The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the first quarter of 2017 :
 
 
Grant Date Fair Value Assumptions
Expected term (in years)
 
4.24

Expected volatility
 
54.3
%
Risk-free interest rate
 
1.8
%
Dividend yield
 
%
Grant date fair value
 
$12.00
Performance Shares. Under the Incentive Plan, the Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest is based on the ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. As of March 31, 2017 , unrecognized compensation costs related to unvested performance shares was $3.8 million and will be recognized over a weighted average period of 2.1 years.

- 13 -


The table below summarizes performance share activity for the first quarter of 2017 :
 
 
Performance Shares
 
Weighted Average Grant Date
Fair Value
For the Three Months Ended March 31, 2017
 
 
 
 
Unvested performance shares, beginning of period
 
154,510

 

$58.44

Granted
 
46,787

 

$35.14

Vested (1)
 
(56,342
)
 

$68.15

Forfeited
 

 

Unvested performance shares, end of period
 
144,955

 

$47.14

 
(1)
The vested performance shares presented in the table above are the target performance shares that were granted in 2014. The Company s final TSR ranking relative to the specified industry peer group resulted in the vesting of 164% of the target performance shares granted, or an additional 35,858 shares.
During the first quarter of 2017, the Company granted 46,787 target performance shares to certain employees and independent contractors with a grant date fair value of $1.6 million as part of its annual grant of long-term equity incentive awards. The grant date fair value of the performance awards was calculated using a Monte Carlo simulation. In addition to the market condition described above, the performance shares also contain a service condition and performance condition. The performance condition has not yet been met.
The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the first quarter of 2017 :
 
 
Grant Date Fair Value Assumptions
Number of simulations
 
500,000
Expected term (in years)
 
2.98

Expected volatility
 
59.2
%
Risk-free interest rate
 
1.5
%
Dividend yield
 
%
Grant date fair value
 
$35.14
Stock-Based Compensation Expense, Net
The Company recognized the following stock-based compensation expense, net for the periods indicated:
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands)
Restricted stock awards and units
 

$5,849

 

$11,594

Stock appreciation rights
 
(3,686
)
 
1,232

Performance shares
 
706

 
616

 
 
2,869

 
13,442

Less: amounts capitalized to oil and gas properties
 
(855
)
 
(1,920
)
Total stock-based compensation expense, net
 

$2,014

 

$11,522

9. Derivative Instruments
The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, three-way collars and purchased and sold call options, which are described below.
Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.


- 14 -


Three-Way Collars: A three-way collar is a combination of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the market price is between the fixed floor price and the fixed sub-floor price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the market price, respectively. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party.
Sold Call Options : These contracts give the counterparties the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparties to pay premiums to the Company that represent the fair value of the call option as of the date of purchase.
Purchased Call Options : These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparties over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the counterparties pay the Company the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparties that represent the fair value of the call option as of the date of purchase.
All of the Company’s purchased call options were executed contemporaneously with sales of call options to increase the fixed price of existing sold call options and therefore are presented on a net basis in the summary of open crude oil derivative positions below.
Premiums : In lieu of receiving payments for premiums from its counterparties of sold call options, the Company has used the associated premium value to obtain higher fixed prices on fixed price swaps which were executed contemporaneously with those sold call options. The Company elected to defer payment of premiums associated with its purchased call options until the applicable contracts settle on a monthly basis. As of March 31, 2017, the Company had premium obligations of approximately $4.2 million , of which $2.0 million is classified as current derivative liabilities and $2.2 million is classified as noncurrent derivative liabilities on the Company’s consolidated balance sheets. As of December 31, 2016, the Company had premium obligations of approximately $4.6 million , of which $2.0 million was classified as current derivative liabilities and $2.6 million was classified as noncurrent derivative liabilities on the Company’s consolidated balance sheets.
The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of March 31, 2017 :
Period    
 
Type of Contract
 
Crude Oil Volumes
(in Bbls/d)
 
Weighted
Average
Floor Price
($/Bbl)
 
Weighted
Average
Ceiling Price
($/Bbl)
Q2 2017
 
Fixed Price Swaps
 
12,000

 

$50.13

 
 
Q3 2017
 
Fixed Price Swaps
 
6,000

 

$54.15

 
 
Q4 2017
 
Fixed Price Swaps
 
3,000

 

$55.01

 
 
FY 2018
 
Sold Call Options
 
2,488

 
 
 

$60.00

FY 2018
 
Net Sold Call Options
 
900

 
 
 

$75.00

FY 2019
 
Sold Call Options
 
2,975

 
 
 

$62.50

FY 2019
 
Net Sold Call Options
 
900

 
 
 

$77.50

FY 2020
 
Sold Call Options
 
3,675

 
 
 
$65.00
FY 2020
 
Net Sold Call Options
 
900

 
 
 
$80.00

- 15 -


The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of March 31, 2017 :
Period    
 
Type of Contract
 
Natural Gas Volumes
(in MMBtu/d)
 
Weighted Average
Floor Price ($/MMBtu)
 
Weighted
Average
Ceiling Price
($/MMBtu)
Q2 - Q4 2017
 
Fixed Price Swaps
 
20,000

 

$3.30

 
 
Q2 - Q4 2017
 
Sold Call Options
 
33,000

 
 
 

$3.00

FY 2018
 
Sold Call Options
 
33,000

 
 
 

$3.25

FY 2019
 
Sold Call Options
 
33,000

 
 
 

$3.25

FY 2020
 
Sold Call Options
 
33,000

 
 
 

$3.50

See “Note 13. Subsequent Events” for details of derivative positions entered into subsequent to March 31, 2017 .
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, including the deferred premiums associated with its hedge positions. The Company nets its derivative instrument fair values executed with the same counterparty along with deferred premiums 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.
Counterparties to the Company’s derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds our unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.
Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties or its counterparty’s parent company.

- 16 -


Derivative Assets and Liabilities
All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The combined derivative instrument fair value assets and liabilities recorded in the Company’s consolidated balance sheets as of March 31, 2017 and December 31, 2016 are summarized below:
 
 
March 31, 2017
 
 
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-current
 

$2,417

 

($1,381
)
 

$1,036

Derivative assets-non current
 
106

 
(106
)
 

Derivative liabilities
 
 
 
 
 
 
Derivative liabilities-current
 
(8,837
)
 
1,381

 
(7,456
)
Derivative liabilities-non current
 
(18,781
)
 
106

 
(18,675
)
Total
 

($25,095
)
 

$—

 

($25,095
)
 
 
December 31, 2016
 
 
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-current
 

$6,507

 

($5,270
)
 

$1,237

Derivative assets-non current
 
1,313

 
(1,313
)
 

Derivative liabilities
 
 
 
 
 
 
Derivative liabilities-current
 
(27,871
)
 
5,270

 
(22,601
)
Derivative liabilities-non current
 
(28,841
)
 
1,313

 
(27,528
)
Total
 

($48,892
)
 

$—

 

($48,892
)
See “Note 10. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative positions.
(Gain) Loss on Derivatives, Net
The Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of derivative instruments are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. The effect of derivative instruments on the Company’s consolidated statements of operations for the three months ended March 31, 2017 and 2016 by commodity is summarized below:
 
 
 Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands)
(Gain) Loss on Derivatives, Net
 
 
 
 
Crude oil
 

($18,480
)
 

($21,891
)
Natural gas
 
(6,836
)
 
11,338

Total (Gain) Loss on Derivatives, Net
 

($25,316
)
 

($10,553
)
The cash flow impacts of the Company’s derivative instruments are presented as separate line items within the net cash provided by operating activities in the Company’s consolidated statements of cash flows.

- 17 -


10. 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 Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016 :
 
 
March 31, 2017
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
Derivative assets
 

$—

 

$1,036

 

$—

Derivative liabilities
 

$—

 

($21,970
)
 

$—

 
 
December 31, 2016
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
Derivative assets
 

$—

 

$1,237

 

$—

Derivative liabilities
 

$—

 

($45,552
)
 

$—

The Company uses Level 2 inputs to measure the fair value of the Company’s commodity derivative instruments based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities.
The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, 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, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty, along with deferred premiums, 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 Company had no transfers into Level 1 and no transfers into or out of Level 2 for the three months ended March 31, 2017 and 2016 .
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate.
The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include 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.

- 18 -


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 carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of debt premiums and debt issuance costs, with the fair values measured using Level 1 inputs based on quoted secondary market trading prices.
 
 
March 31, 2017
 
December 31, 2016
 
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
 
(In thousands)
7.50% Senior Notes due 2020
 

$593,771

 

$616,500

 

$593,447

 

$624,750

6.25% Senior Notes due 2023
 
640,850

 
650,000

 
640,546

 
672,750

Other long-term debt due 2028
 
4,425

 
4,425

 
4,425

 
4,419

11. 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 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.

- 19 -


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(In thousands)
(Unaudited)
 
 
March 31, 2017
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Total current assets
 

$2,724,856

 

$66,199

 

$—

 

($2,717,829
)
 

$73,226

Total property and equipment, net
 
41,196

 
1,593,134

 
3,800

 
(3,926
)
 
1,634,204

Investment in subsidiaries
 
(1,223,475
)
 

 

 
1,223,475

 

Other assets
 
6,855

 
155

 

 

 
7,010

Total Assets
 

$1,549,432

 

$1,659,488

 

$3,800

 

($1,498,280
)
 

$1,714,440

 
 
 
 
 
 
 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$90,083

 

$2,854,994

 

$3,800

 

($2,720,849
)
 

$228,028

Long-term liabilities
 
1,372,638

 
27,969

 

 
15,878

 
1,416,485

Total shareholders’ equity
 
86,711

 
(1,223,475
)
 

 
1,206,691

 
69,927

Total Liabilities and Shareholders’ Equity
 

$1,549,432

 

$1,659,488

 

$3,800

 

($1,498,280
)
 

$1,714,440

 
 
December 31, 2016
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Total current assets
 

$2,735,830

 

$63,513

 

$—

 

($2,726,355
)
 

$72,988

Total property and equipment, net
 
42,181

 
1,503,695

 
3,800

 
(3,916
)
 
1,545,760

Investment in subsidiaries
 
(1,282,292
)
 

 

 
1,282,292

 

Other assets
 
7,423

 
156

 

 

 
7,579

Total Assets
 

$1,503,142

 

$1,567,364

 

$3,800

 

($1,447,979
)
 

$1,626,327

 
 
 
 
 
 
 
 
 
 
 
Liabilities and Shareholders’ Equity
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$114,805

 

$2,822,729

 

$3,800

 

($2,729,375
)
 

$211,959

Long-term liabilities
 
1,348,105

 
26,927

 

 
15,878

 
1,390,910

Total shareholders’ equity
 
40,232

 
(1,282,292
)
 

 
1,265,518

 
23,458

Total Liabilities and Shareholders’ Equity
 

$1,503,142

 

$1,567,364

 

$3,800

 

($1,447,979
)
 

$1,626,327


- 20 -


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
 
 
Three Months Ended March 31, 2017
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$82

 

$151,273

 

$—

 

$—

 

$151,355

Total costs and expenses
 
18,868

 
92,456

 

 
10

 
111,334

Income (loss) before income taxes
 
(18,786
)
 
58,817

 

 
(10
)
 
40,021

Income tax expense
 

 

 

 

 

Equity in income of subsidiaries
 
58,817

 

 

 
(58,817
)
 

Net income
 

$40,031

 

$58,817

 

$—

 

($58,827
)
 

$40,021

 
 
Three Months Ended March 31, 2016
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total revenues
 

$115

 

$81,147

 

$—

 

$—

 

$81,262

Total costs and expenses
 
29,912

 
362,248

 

 
376

 
392,536

Loss before income taxes
 
(29,797
)
 
(281,101
)
 

 
(376
)
 
(311,274
)
Income tax expense
 

 

 

 
(121
)
 
(121
)
Equity in loss of subsidiaries
 
(281,101
)
 

 

 
281,101

 

Net loss
 

($310,898
)
 

($281,101
)
 

$—

 

$280,604

 

($311,395
)

- 21 -


CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
 
Three Months Ended March 31, 2017
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
 

($47,297
)
 

$123,705

 

$—

 

$—

 

$76,408

Net cash provided by (used in) investing activities
 
9,879

 
(114,212
)
 

 
(9,493
)
 
(113,826
)
Net cash provided by (used in) financing activities
 
35,615

 
(9,493
)
 

 
9,493

 
35,615

Net decrease in cash and cash equivalents
 
(1,803
)
 

 

 

 
(1,803
)
Cash and cash equivalents, beginning of period
 
4,194

 

 

 

 
4,194

Cash and cash equivalents, end of period
 

$2,391

 

$—

 

$—

 

$—

 

$2,391

 
 
Three Months Ended March 31, 2016
 
 
Parent
Company
 
Combined
Guarantor
Subsidiaries
 
Combined
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
 

($2,156
)
 

$56,024

 

$—

 

$—

 

$53,868

Net cash used in investing activities
 
(68,797
)
 
(122,849
)
 
(740
)
 
67,565

 
(124,821
)
Net cash provided by financing activities
 
30,193

 
66,825

 
740

 
(67,565
)
 
30,193

Net decrease in cash and cash equivalents
 
(40,760
)
 

 

 

 
(40,760
)
Cash and cash equivalents, beginning of period
 
42,918

 

 

 

 
42,918

Cash and cash equivalents, end of period
 

$2,158

 

$—

 

$—

 

$—

 

$2,158


- 22 -


12. Supplemental Cash Flow Information
Supplemental cash flow disclosures and non-cash investing activities are presented below:
 
 
Three Months Ended
March 31,
 
 
2017
 
2016
 
 
(In thousands)
Supplemental cash flow disclosures:
 
 
 
 
Cash paid for interest, net of amounts capitalized
 

$19,480

 

$17,553

Cash paid for income taxes
 

 

 
 
 
 
 
Non-cash investing activities:
 
 
 
 
Increase (decrease) in capital expenditure payables and accruals
 

$28,139

 

($27,989
)
Stock-based compensation expense capitalized to oil and gas properties
 
855

 
1,920

Asset retirement obligations capitalized to oil and gas properties
 
447

 
518

Other non-cash investing activities
 
343

 
1,485

13. Subsequent Events
Hedging
In April 2017, the Company entered into the following crude oil derivative positions:
Period
 
Type of Contract
 
Crude Oil
Volumes
(in Bbls/d)
 
Weighted
Average
Sub-Floor Price
($/Bbl)
 
Weighted
Average
Floor Price
($/Bbl)
 
Weighted
Average
Ceiling Price
($/Bbl)
Q3 2017
 
Fixed Price Swaps
 
6,000

 
 
 

$53.28

 
 
Q4 2017
 
Fixed Price Swaps
 
6,000

 
 
 

$53.28

 
 
FY 2018
 
Three-Way Collars
 
6,000

 

$40.00

 

$50.00

 

$65.00

In order to obtain a higher weighted average ceiling price on the three-way collars, the Company incurred premiums of approximately $2.8 million , the payments for which are deferred until the applicable contracts settle on a monthly basis.
Sanchez Acquisition
In April 2017, the Company paid $9.8 million for the remaining outstanding leases that were not conveyed to the Company at the initial closing on December 14, 2016 or at the subsequent closing on January 9, 2017. The Company currently expects its allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date will be finalized during the fourth quarter of 2017.
Ninth Amendment to Credit Agreement
On May 4, 2017, the Company entered into a ninth amendment to its credit agreement governing the revolving credit facility to, among other things (i) extend the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion , (iii) increase the borrowing base from $600.0 million to $900.0 million , of which $800.0 million has been committed by lenders, until the next redetermination thereof, (iv) replace the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio covenant that requires such ratio not to exceed 4.00 to 1.00, (v) remove the covenant requiring a minimum EBITDA to Interest Expense ratio, (vi) reduce the commitment fee from 0.50% to 0.375% when utilization of lender commitments is less than 50% of the borrowing base amount, (vii) remove the restriction from borrowing under the credit facility if the Company has or, after giving effect to the borrowing, will have a Consolidated Cash Balance in excess of $50.0 million , (viii) remove the mandatory repayment of borrowings to the extent the Consolidated Cash Balance exceeds $50.0 million if either (a) the Company’s ratio of Total Debt to EBITDA exceeds 3.50 to 1.00 or (b) the availability under the credit facility is equal to or less than 20% of the then effective borrowing base, (ix) permit the issuance of unlimited Senior Unsecured Debt, subject to certain conditions, including pro forma compliance with the Company’s financial covenants, and (x) increase certain covenant baskets and thresholds. The capitalized terms which are not defined in this note to the consolidated financial statements have the meaning given to such terms in the credit agreement.



- 23 -


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our 2016 Annual Report. The following discussion and analysis contains statements, including, but not limited to, statements related to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” for further details about these statements.
General Overview
Operational Results . Total production for the three months ended March 31, 2017 increased 10% from the three months ended March 31, 2016 to 46,367 Boe/d primarily due to increased production from new wells in the Eagle Ford and Delaware Basin, production from the Sanchez Acquisition, and increased production in the Marcellus due to a lower level of voluntary curtailments compared to the first quarter of 2016, partially offset by normal production declines. Crude oil production for the three months ended March 31, 2017 was 28,844 Bbls/d, an increase of 12% from the three months ended March 31, 2016 , primarily driven by increased production from new wells in the Eagle Ford and Delaware Basin and the Sanchez Acquisition, partially offset by normal production declines. For further discussion of production, see “—Results of Operations” below.
See the table below for details of our operated drilling and completion activity:
 
 
Three Months Ended March 31, 2017
 
March 31, 2017
 
 
Drilled
 
Completed
 
Drilled But Uncompleted
 
Producing
 
Rig count
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Eagle Ford
 
24

 
20.1

 
29

 
28.7

 
29

 
23.9

 
463

 
399.4

 
3

Delaware Basin
 

 

 

 

 
2

 
2.0

 
6

 
5.6

 

Niobrara
 

 

 

 

 

 

 
130

 
57.9

 

Marcellus
 

 

 

 

 
11

 
4.3

 
81

 
26.0

 

Utica and Other
 

 

 

 

 

 

 
4

 
3.1

 

Total
 
24

 
20.1

 
29

 
28.7

 
42

 
30.2

 
684

 
492.0

 
3

Drilling and completion expenditures for the first quarter of 2017 were $128.2 million, of which 87% were in the Eagle Ford where, as of March 31, 2017, we were operating three rigs and two frac crews. Our current 2017 capital expenditure plan includes $530.0 million to $550.0 million for drilling and completion and $45.0 million for leasehold and seismic, which was recently increased from $20.0 million. The focus for our remaining 2017 drilling and completion capital expenditures is currently on the continued exploration and development of oil-focused plays, such as the Eagle Ford and Delaware Basin, where approximately 90% of our currently remaining 2017 drilling and completion capital expenditure plan is allocated. See “—Liquidity and Capital Resources—2017 Capital Expenditure Plan and Funding Strategy” for additional details.
Senior Secured Revolving Credit Facility. On May 4, 2017, we entered into entered into a ninth amendment to our credit agreement governing the revolving credit facility which, among other things, (i) extended the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time, (ii) increased the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, and (iii) increased the borrowing base from $600.0 million to $900.0 million, of which $800.0 million has been committed by lenders, until the next redetermination thereof. See “Note 13. Subsequent Events” for further details.
Financial Results. We recorded net income for the three months ended March 31, 2017 of $40.0 million, or $0.61 per diluted share, as compared to a net loss for the three months ended March 31, 2016 of $311.4 million, or $5.34 per diluted share. The net income for the first quarter of 2017 as compared to the net loss for the first quarter of 2016 was driven primarily by an increase in revenues as a result of higher realized crude oil pricing and production as well as no impairment of proved oil and gas properties during the first quarter of 2017 compared to an impairment of proved oil and gas properties of $274.4 million recognized during the first quarter of 2016. See “—Results of Operations” below for further details.

- 24 -


Results of Operations
Three Months Ended March 31, 2017 , Compared to the Three Months Ended March 31, 2016
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended March 31, 2017 and 2016 :
 
 
 Three Months Ended
March 31,
 
2017 Period
Compared to 2016 Period
 
 
2017
 
2016
 
Increase (Decrease)
 
% Increase (Decrease)
Total production volumes -
 
 
 
 
 
 
 
 
    Crude oil (MBbls)
 
2,596

 
2,348

 
248

 
11
%
    NGLs (MBbls)
 
406

 
414

 
(8
)
 
(2
%)
    Natural gas (MMcf)
 
7,028

 
6,373

 
655

 
10
%
Total barrels of oil equivalent (MBoe)
 
4,173


3,824

 
349

 
9
%
 
 
 
 
 
 
 
 
 
Daily production volumes by product -
 
 
 
 
 
 
 
 
    Crude oil (Bbls/d)
 
28,844

 
25,806

 
3,038

 
12
%
    NGLs (Bbls/d)
 
4,508

 
4,547

 
(39
)
 
(1
%)
    Natural gas (Mcf/d)
 
78,088

 
70,033

 
8,055

 
12
%