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 crude oil, NGLs, and gas located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.
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 recently adopted accounting pronouncement described below and the accounting for the ExL Acquisition and related financing. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties”, “Note
8.
Preferred Stock”, “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
Recently Adopted Accounting Pronouncement
Stock Compensation.
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
Business Combinations.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is to be applied on a
prospective basis and is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The Company currently plans to adopt the guidance on the effective date of January 1, 2018.
Statement of Cash Flows.
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, with early adoption permitted, provided that it is adopted in its entirety in the same period. Companies are required to use a full retrospective approach, meaning the standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows and related disclosures upon adoption. The Company plans to adopt the guidance on the effective date of January 1, 2018.
Leases.
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.
The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements and current accounting policies and disclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of the new standard are also being evaluated. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company plans to adopt the guidance on the effective date of January 1, 2019.
Revenue From Contracts With Customers.
In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 using either a full retrospective approach, which is described above, 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 currently assessing the impact of ASU 2014-09 which includes an analysis of existing contracts and current accounting policies and disclosures to identify potential differences that would result from applying the requirements of the new standard. Appropriate changes to business processes, systems or controls will be implemented to support recognition and disclosure under the new standard. Although its assessment is in progress, the Company currently does not expect the adoption of ASU 2014-09 to have a material impact on its consolidated financial statements because existing contractual performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of the Company’s existing contracts will continue to be recognized as control of products is transferred to the customer. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.
Net Income (Loss) Per Common Share
Supplemental net income (loss) per common share information is provided below:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In thousands, except per share amounts)
|
|
Net Income (Loss) Attributable to Common Shareholders
|
|
|
$5,574
|
|
|
|
($101,174
|
)
|
|
|
$101,901
|
|
|
|
($674,695
|
)
|
|
Basic weighted average common shares outstanding
|
|
81,053
|
|
|
58,945
|
|
|
70,728
|
|
|
58,705
|
|
|
Effect of dilutive instruments
|
|
85
|
|
|
—
|
|
|
419
|
|
|
—
|
|
|
Diluted weighted average common shares outstanding
|
|
81,138
|
|
|
58,945
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|
|
71,147
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|
58,705
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|
Net Income (Loss) Attributable to Common Shareholders Per Common Share
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Basic
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|
$0.07
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|
($1.72
|
)
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|
$1.44
|
|
|
|
($11.49
|
)
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Diluted
|
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|
$0.07
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|
|
($1.72
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)
|
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|
$1.43
|
|
|
|
($11.49
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)
|
When the Company recognizes a net loss, as was the case for the three months and nine months ended September 30, 2016, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The table below presents the weighted average dilutive and anti-dilutive securities outstanding for the periods presented which consisted of unvested restricted stock awards and units, unvested performance shares and exercisable common stock warrants:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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|
|
2017
|
|
2016
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|
2017
|
|
2016
|
|
|
|
(In thousands)
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|
Dilutive
|
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85
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|
—
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419
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|
—
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Anti-dilutive
|
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882
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|
698
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|
120
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|
|
664
|
|
3.
Acquisitions and Divestitures of Oil and Gas Properties
Acquisitions
ExL Acquisition.
On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for a purchase price of
$648.0 million
, subject to customary purchase price adjustments (the “ExL Acquisition”). The transaction had an effective date of May 1, 2017. The Company paid
$75.0 million
to the seller as a deposit on June 28, 2017 and
$601.0 million
upon closing on August 10, 2017, which included preliminary purchase price adjustments primarily related to the net cash flows from the acquired wells and capital expenditures from the effective date to the closing date. Upon closing the ExL Acquisition, the Company became the operator of the ExL Properties with an approximate
70%
average working interest.
The Company also agreed to pay an additional
$50.0 million
per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above
$50.00
for any of the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This payment (the “Contingent ExL Payment”) will be
zero
for the respective year if such EIA WTI average price of a barrel of oil is
$50.00
or below for any of such years, and the Contingent ExL Payment is capped at
$125.0 million
in the aggregate. The Company determined that the Contingent ExL Payment is an embedded derivative and has reflected the liability at fair value in the consolidated financial statements. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was
$60.3 million
and
$52.3 million
, respectively. See “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note
8.
Preferred Stock” for details regarding the sale of Preferred Stock, “Note
9.
Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering and “Note
6.
Long-Term Debt” for details regarding the senior notes offering.
The ExL Acquisition was accounted for under the acquisition method of accounting whereby the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in
determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Payment was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note
11.
Fair Value Measurements” for further details.
The purchase price allocation for the ExL Acquisition is preliminary and subject to change based on updates to purchase price adjustments primarily related to net cash flows from the acquired wells and capital expenditures from the effective date to the closing date. The Company currently expects to finalize its allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date during the third quarter of 2018. 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.
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Preliminary Purchase Price Allocation
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(In thousands)
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Assets
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Other current assets
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$106
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Oil and gas properties
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Proved properties
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292,551
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Unproved properties
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443,194
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Total oil and gas properties
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$735,745
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Total assets acquired
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$735,851
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Liabilities
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Revenues and royalties payable
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|
$5,036
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|
Asset retirement obligations
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|
153
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Contingent ExL Payment
|
|
52,300
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Total liabilities assumed
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|
$57,489
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|
Net Assets Acquired
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|
$678,362
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Included in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of
$14.0 million
and income before income taxes of
$11.4 million
from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.
Pro Forma Operating Results (Unaudited).
The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three and nine month periods ended September 30, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition.
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Three Months Ended September 30,
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Nine Months Ended September 30,
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2017
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2016
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2017
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2016
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|
(In thousands, except per share amounts)
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|
Total revenues
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|
$189,499
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|
|
$115,065
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$534,607
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|
$305,074
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|
Net Income (Loss) Attributable to Common Shareholders
|
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|
$14,654
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|
($106,598
|
)
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|
$115,053
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|
($688,902
|
)
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Net Income (Loss) Attributable to Common Shareholders Per Common Share
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Basic
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|
$0.18
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|
|
($1.43
|
)
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|
$1.63
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|
|
|
($9.27
|
)
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Diluted
|
|
|
$0.18
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|
|
|
($1.43
|
)
|
|
|
$1.62
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|
|
($9.27
|
)
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|
Weighted Average Common Shares Outstanding
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Basic
|
|
81,053
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|
|
74,545
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|
|
70,728
|
|
|
74,305
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|
Diluted
|
|
81,138
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|
|
74,545
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|
|
71,147
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|
|
74,305
|
|
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 transaction had an effective date of June 1, 2016 and 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 closing, 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 and April 13, 2017, the Company paid
$7.0 million
and
$9.8 million
, respectively, for these outstanding leases when conveyed to the Company.
The following presents the allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
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Purchase Price Allocation
|
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(In thousands)
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Assets
|
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Other current assets
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$477
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|
Oil and gas properties
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Proved properties
|
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99,938
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|
Unproved properties
|
|
74,536
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|
Total oil and gas properties
|
|
|
$174,474
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Total assets acquired
|
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|
$174,951
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|
Liabilities
|
|
|
|
Revenues and royalties payable
|
|
|
$1,442
|
|
|
Other current liabilities
|
|
323
|
|
|
Asset retirement obligations
|
|
2,054
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|
|
Other liabilities
|
|
1,078
|
|
|
Total liabilities assumed
|
|
|
$4,897
|
|
|
Net Assets Acquired
|
|
|
$170,054
|
|
Included in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of
$9.1 million
and
$23.2 million
, respectively, and income before income taxes of
$4.0 million
and
$7.1 million
, respectively, from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.
Divestitures
Potential Divestiture of Utica Assets.
On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale, located primarily in Guernsey County, Ohio, for an agreed upon price of
$62.0 million
. The transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. The Company received
$6.2 million
from the buyer as a deposit on August 31, 2017.
The Company could also receive contingent consideration of
$5.0 million
per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above
$50.00
,
$53.00
, and
$56.00
for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be
zero
for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years, and is capped at
$15.0 million
.
Other Assets.
During the first quarter of 2017, the Company sold a small undeveloped 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.
4.
Property and Equipment, Net
As of
September 30, 2017
and
December 31, 2016
, total property and equipment, net consisted of the following:
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|
|
|
September 30,
2017
|
|
December 31,
2016
|
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|
(In thousands)
|
|
Oil and gas properties, full cost method
|
|
|
|
|
|
Proved properties
|
|
|
$5,452,201
|
|
|
|
$4,687,416
|
|
|
Accumulated depreciation, depletion and amortization and impairments
|
|
(3,569,626
|
)
|
|
(3,392,749
|
)
|
|
Proved properties, net
|
|
1,882,575
|
|
|
1,294,667
|
|
|
Unproved properties, not being amortized
|
|
|
|
|
|
Unevaluated leasehold and seismic costs
|
|
697,370
|
|
|
211,067
|
|
|
Capitalized interest
|
|
42,835
|
|
|
29,894
|
|
|
Total unproved properties, not being amortized
|
|
740,205
|
|
|
240,961
|
|
|
Other property and equipment
|
|
25,344
|
|
|
23,127
|
|
|
Accumulated depreciation
|
|
(14,806
|
)
|
|
(12,995
|
)
|
|
Other property and equipment, net
|
|
10,538
|
|
|
10,132
|
|
|
Total property and equipment, net
|
|
|
$2,633,318
|
|
|
|
$1,545,760
|
|
Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was
$13.04
and
$12.72
for the
three months ended September 30,
2017
and
2016
, respectively, and
$12.73
and
$13.79
for the
nine months ended September 30,
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
$3.3 million
and
$2.7 million
for the
three months ended September 30,
2017
and
2016
, respectively, and
$10.6 million
and
$8.5 million
for the
nine months ended September 30,
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
$8.5 million
and
$2.9 million
for the
three months ended September 30,
2017
and
2016
, respectively, and
$16.2 million
and
$13.4 million
for the
nine months ended September 30,
2017
and
2016
, respectively.
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.
The Company did not recognize impairments of proved oil and gas properties for the
three and nine months ended September 30,
2017
. Primarily due to declines in the 12-Month Average Realized Prices of crude oil, the Company recognized impairments of proved oil and gas properties for the
three and nine months ended September 30,
2016
. Details of the 12-Month Average Realized Price of crude oil for the
three and nine months ended September 30,
2017
and
2016
and the impairments of proved oil and gas properties for the
three and nine months ended September 30,
2016
are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Impairment of proved oil and gas properties (in thousands)
|
|
|
$—
|
|
|
$105,057
|
|
|
$—
|
|
|
$576,540
|
|
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period
|
|
$46.80
|
|
$39.84
|
|
$39.60
|
|
$47.24
|
|
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period
|
|
$47.74
|
|
$38.36
|
|
$47.74
|
|
$38.36
|
|
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period
|
|
2
|
%
|
|
(4
|
%)
|
|
21
|
%
|
|
(19
|
%)
|
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
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
|
Income (loss) before income taxes
|
|
|
$7,823
|
|
|
|
($101,487
|
)
|
|
|
$104,150
|
|
|
|
($674,695
|
)
|
|
Income tax (expense) benefit at the statutory rate
|
|
(2,738
|
)
|
|
35,520
|
|
|
(36,452
|
)
|
|
236,143
|
|
|
State income tax (expense) benefit, net of U.S. federal income taxes
|
|
(247
|
)
|
|
575
|
|
|
(1,974
|
)
|
|
3,859
|
|
|
Tax shortfalls from stock-based compensation expense
|
|
(273
|
)
|
|
—
|
|
|
(3,029
|
)
|
|
—
|
|
|
(Increase) decrease in deferred tax assets valuation allowance
|
|
3,253
|
|
|
(36,696
|
)
|
|
41,570
|
|
|
(240,897
|
)
|
|
Other
|
|
5
|
|
|
914
|
|
|
(115
|
)
|
|
895
|
|
|
Income tax benefit
|
|
|
$—
|
|
|
|
$313
|
|
|
|
$—
|
|
|
|
$—
|
|
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
September 30, 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 third 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
September 30, 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 and nine months ended September 30, 2017, primarily as a result of current activity, partial releases of
$3.3 million
and
$41.6 million
, respectively, from the valuation allowance was recorded to bring the net deferred tax assets to
zero
. After the impact of the partial release the valuation allowance as of September 30, 2017 was
$538.5 million
. For the three and nine months ended September 30, 2016, the Company recorded additional valuation allowances of
$36.7 million
and
$240.9 million
, respectively, primarily as a result of the impairments of proved oil and gas properties during these periods.
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
September 30, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
December 31,
2016
|
|
|
|
(In thousands)
|
|
Senior Secured Revolving Credit Facility due 2022
|
|
|
$215,600
|
|
|
|
$87,000
|
|
|
7.50% Senior Notes due 2020
|
|
600,000
|
|
|
600,000
|
|
|
Unamortized premium for 7.50% Senior Notes
|
|
836
|
|
|
1,020
|
|
|
Unamortized debt issuance costs for 7.50% Senior Notes
|
|
(6,397
|
)
|
|
(7,573
|
)
|
|
6.25% Senior Notes due 2023
|
|
650,000
|
|
|
650,000
|
|
|
Unamortized debt issuance costs for 6.25% Senior Notes
|
|
(8,527
|
)
|
|
(9,454
|
)
|
|
8.25% Senior Notes due 2025
|
|
250,000
|
|
|
—
|
|
|
Unamortized debt issuance costs for 8.25% Senior Notes
|
|
(4,498
|
)
|
|
—
|
|
|
Other long-term debt due 2028
|
|
4,425
|
|
|
4,425
|
|
|
Long-term debt
|
|
|
$1,701,439
|
|
|
|
$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
September 30, 2017
, had a borrowing base of
$837.5 million
, with an elected commitment amount of
$800.0 million
, and
$215.6 million
of borrowings outstanding at a weighted average interest rate of
3.45%
. As of
September 30, 2017
, the Company had
$0.4 million
in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until 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), when the credit agreement matures and any outstanding borrowings are 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.
On May 4, 2017, the Company entered into a ninth amendment to the 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 or redeemed 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
, with an elected commitment amount of
$800.0 million
, 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.
On June 28, 2017, the Company entered into a tenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the quarter ending September 30, 2017, (ii) amend the restricted payments covenant to, among other things, provide for additional capacity to pay dividends with respect to, and make redemptions of, the Company’s equity interests, including the ability, subject to certain conditions, to pay dividends on or make redemptions of the Preferred Stock using proceeds of certain equity issuances or in an amount equal to the proceeds of certain divestitures, (iii) amend the definition of “Disqualified Capital Stock” to provide, among other things, that the Preferred Stock does not constitute “Disqualified Capital Stock” for purposes of the revolving credit facility, (iv) provide that any of the Contingent ExL Payment does not constitute Debt (as defined in the revolving credit facility) for purposes of the revolving credit facility until such time as the amount of such obligation is determined, and (v) amend certain other covenants, in each case as set forth therein. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.
Upon issuance of the
8.25%
Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, the Company’s borrowing base was reduced by
25%
of the aggregate principal amount of the
8.25%
Senior Notes, reducing the Company’s borrowing base from
$900.0 million
to
$837.5 million
.
On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility. See “Note
14.
Subsequent Events” for further details of the eleventh amendment.
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 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%
|
|
0.375%
|
|
Greater than or equal to 25% but less than 50%
|
|
1.25%
|
|
2.25%
|
|
0.375%
|
|
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%
|
The Company is 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 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. As defined in the credit agreement, Total Debt excludes debt discounts, premiums, and debt issuance costs and is net of cash and cash equivalents, EBITDA is calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the fiscal quarter ending September 30, 2017, and thereafter will be calculated based on the last four fiscal quarter periods, in each case after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of
September 30, 2017
, the ratio of Total Debt to EBITDA was
3.09
to 1.00 and the Current Ratio was
2.20
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 divestitures 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 and divestitures of oil and gas properties, mergers, 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).
8.25% Senior Notes due 2025
On July 14, 2017, the Company closed a public offering of
$250.0 million
aggregate principal amount of
8.25%
Senior Notes due 2025 (the “
8.25%
Senior Notes”). The
8.25%
Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the
8.25%
Senior Notes at
100%
of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the
8.25%
Senior Notes at redemption prices decreasing annually from
106.188%
to
100%
of the principal amount redeemed plus accrued and unpaid interest. The Company used the net proceeds of
$245.4 million
, net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.
If a Change of Control (as defined in the indentures governing the
8.25%
Senior Notes) occurs, the Company may be required by holders to repurchase the
8.25%
Senior Notes for cash at a price equal to
101%
of the principal amount purchased, plus any accrued and unpaid interest.
The indentures governing the
8.25%
Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At September 30, 2017, the
8.25%
Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility.
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.
Preferred Stock
On June 28, 2017, the Company entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (i)
$250.0 million
(
250,000
shares) of
8.875%
redeemable preferred stock, par value
$0.01
per share (the “Preferred Stock”) and (ii) warrants for
2,750,000
shares of the Company’s common stock, with a term of
ten
years and an exercise price of
$16.08
per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to
$970.00
per share of Preferred Stock. The Company paid the GSO Funds
$5.0 million
as a commitment fee upon signing the Preferred Stock Purchase Agreement. The closing of the private placement occurred on August 10, 2017, contemporaneously with the closing of the ExL Acquisition. The Company used the net proceeds of approximately
$236.4 million
, net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. The Company also entered into a registration rights agreement with the GSO Funds at the closing of the private placement, which provided certain registration and other rights for the benefit of the GSO Funds. During the fourth quarter of 2017, the Company filed a registration statement with the SEC to register the Preferred Stock. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.
The Preferred Stock has a liquidation preference of
$1,000.00
per share and bears an annual cumulative dividend rate of
8.875%
, payable on March 15, June 15, September 15 and December 15 of any given year. The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending:
|
|
|
|
|
|
|
|
Period
|
|
Percentage
|
|
On or after December 15, 2017 and on or prior to September 15, 2018
|
|
100
|
%
|
|
On or after December 15, 2018 and on or prior to September 15, 2019
|
|
75
|
%
|
|
On or after December 15, 2019 and on or prior to September 15, 2020
|
|
50
|
%
|
If the Company fails to satisfy the Preferred Stock dividend on the applicable dividend payment date, then the unpaid dividend will be added to the liquidation preference until paid.
The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company may redeem up to
50,000
shares of Preferred Stock, in cash, at
$1,000.00
per share, plus accrued and unpaid dividends in an amount not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries. In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at a redemption premium of
104.4375%
, plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends.
|
|
|
|
|
|
|
|
Period
|
|
Percentage
|
|
After August 10, 2020 but on or prior to August 10, 2021
|
|
104.4375
|
%
|
|
After August 10, 2021 but on or prior to August 10, 2022
|
|
102.21875
|
%
|
|
After August 10, 2022
|
|
100
|
%
|
The holders of the Preferred Stock have the option to cause the Company to redeem the Preferred Stock under the following conditions:
|
|
|
|
•
|
Upon the Company’s failure to pay a quarterly dividend within three months of the applicable payment date;
|
|
|
|
|
•
|
On or after August 10, 2024, if the Preferred Shares remain outstanding; or
|
|
|
|
|
•
|
Upon the occurrence of certain changes of control
|
For the first two conditions described above, the Company has the option to settle any such redemption in cash or shares of its common stock and the holders of the Preferred Stock may elect to revoke or reduce the redemption if the Company elects to settle in shares of common stock.
The Preferred Stock are non-voting shares except as required by the Company’s articles of incorporation or bylaws. However, so long as the GSO Funds beneficially own more than
50%
of the Preferred Stock, the consent of the holders of the Preferred Stock will be required prior to issuing stock senior to or on parity with the Preferred Stock, incurring indebtedness subject to a leverage ratio, agreeing to certain restrictions on dividends on, or redemption of, the Preferred Stock and declaring or paying dividends on the Company’s common stock in excess of
$15.0 million
per year subject to a leverage ratio. Additionally, if the Company does not redeem the Preferred Stock before August 10, 2024, in connection with a change of control or failure to pay a quarterly dividend within three months of the applicable payment date, the holders of the Preferred Stock are entitled to additional rights including:
|
|
|
|
•
|
Increasing the dividend rate to
12.0%
per annum until August 10, 2024 and thereafter to the greater of
12.0%
per annum and the one-month LIBOR plus
10.0%
;
|
|
|
|
|
•
|
Electing up to two directors to the Company’s Board of Directors; and
|
|
|
|
|
•
|
Requiring approval by the holders of the Preferred Stock to incur indebtedness subject to a leverage ratio, declaring or paying dividends on the Company’s common stock in excess of
$15.0 million
per year or issuing equity of the Company’s subsidiaries to third parties.
|
The Preferred Stock does not qualify as a liability instrument under ASC 480 - Distinguishing Liabilities from Equity, as the Preferred Stock is not mandatorily redeemable. As the Preferred Stock does not qualify as a liability instrument, the Company next evaluated whether the Preferred Stock should be presented in shareholders' equity or temporary equity, between liabilities and shareholders' equity on its consolidated balance sheets. As the number of common shares that could be required to be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock. As such, the Preferred Stock must be presented as temporary equity. The Company will reassess presentation of the Preferred Stock on its consolidated balance sheets on a quarterly basis.
The Warrants became exercisable upon issuance and qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. The Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets.
Net proceeds were allocated between the Preferred Stock and the Warrants based on their relative fair values at the issuance date, with
$213.4 million
allocated to the Preferred Stock and
$23.0 million
allocated to the Warrants. The fair value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation of the Preferred Stock included the per share cash purchase price, redemption premiums, and liquidation preference, all as discussed
above, as well as redemption assumptions provided by the Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
|
|
|
|
|
|
|
|
|
|
Issuance Date Fair Value Assumptions
|
|
Exercise price
|
|
$16.08
|
|
Expected term (in years)
|
|
10.0
|
|
|
Expected volatility
|
|
62.9
|
%
|
|
Risk-free interest rate
|
|
2.2
|
%
|
|
Dividend yield
|
|
—
|
%
|
See “Note
11.
Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock and Warrants fair value calculations.
Preferred Stock Dividends and Accretion
In the third quarter of 2017, the Company declared and paid
$2.2 million
of dividends, in cash, to the holders of record of the Preferred Stock on September 1, 2017 for the period from issuance through September 15, 2017.
The Preferred Stock will be subject to accretion from its relative fair value at the issuance date of
$213.4 million
to a redemption value of
$250.0 million
over an approximate seven year term using the effective interest method.
Both the dividends and the accretion are presented on the statements of operations as reductions to net income, or increases to net loss, to compute net income (loss) attributable to common shareholders.
9.
Shareholders’ Equity and Stock-Based Compensation
Increase in Authorized Common Shares
At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved the proposal to amend the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from
90,000,000
to
180,000,000
.
Sale of Common Stock
On July 3, 2017, the Company completed a public offering of
15.6 million
shares of its common stock at a price per share of
$14.28
. The Company used the net proceeds of
$222.4 million
, net of offering costs, to fund a portion of the purchase price of the ExL Acquisition and for general corporate purposes. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.
Stock-Based Compensation
At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. The 2017 Incentive Plan provides that up to
2,675,000
shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan, may be issued.
As of
September 30, 2017
, there were
1,750,275
common shares remaining available for grant under the 2017 Incentive Plan. The issuance of a restricted stock award, restricted stock unit, or performance share counts as
1.35
shares while the issuance of a stock option or stock-settled stock appreciation right counts as
1.00
share against the number of common shares available for grant under the 2017 Incentive Plan. As of
September 30, 2017
, the Company does not have any outstanding stock options and all outstanding stock appreciation rights will be settled solely in cash.
Restricted Stock Awards and Units.
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
September 30, 2017
, unrecognized compensation costs related to unvested restricted stock awards and units was
$26.3 million
and will be recognized over a weighted average period of
2.1
years.
The table below summarizes restricted stock award and unit activity for the
nine months ended September 30,
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
|
For the Nine Months Ended September 30, 2017
|
|
|
|
|
|
Unvested restricted stock awards and units, beginning of period
|
|
1,111,710
|
|
|
|
$36.93
|
|
|
Granted
|
|
1,020,465
|
|
|
|
$25.63
|
|
|
Vested
|
|
(629,397
|
)
|
|
|
$39.58
|
|
|
Forfeited
|
|
(12,922
|
)
|
|
|
$29.11
|
|
|
Unvested restricted stock awards and units, end of period
|
|
1,489,856
|
|
|
|
$28.14
|
|
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. 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 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.
During the second quarter of 2017, the Company granted
206,548
restricted stock awards and units to employees and non-employee directors with a grant date fair value of
$5.0
million, all of which contain a service condition.
Stock Appreciation Rights (“SARs”).
SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) or the 2017 Incentive Plan. SARs granted under the 2017 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. All outstanding SARs will be settled solely in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of
September 30, 2017
was
$2.3 million
, all of which was 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
$1.3 million
as of
September 30, 2017
, and will be recognized over a weighted average period of
1.3
years.
The table below summarizes the activity for SARs for the
nine months ended September 30,
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 Nine Months Ended September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
722,638
|
|
|
|
$23.69
|
|
|
|
|
|
|
|
|
Granted
|
|
342,440
|
|
|
|
$26.94
|
|
|
|
|
|
|
|
|
Exercised
|
|
(219,279
|
)
|
|
|
$17.28
|
|
|
|
|
|
|
|
$2.1
|
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
|
|
|
|
|
|
|
Expired
|
|
(131,561
|
)
|
|
|
$24.19
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
714,238
|
|
|
|
$27.12
|
|
|
4.0
|
|
|
$—
|
|
|
|
|
Vested, end of period
|
|
185,899
|
|
|
|
$27.30
|
|
|
|
|
|
|
|
|
Vested and exercisable, end of period
|
|
—
|
|
|
|
$27.30
|
|
|
3.5
|
|
|
$—
|
|
|
|
During the first quarter of 2017, the Company granted
342,440
SARs under the Cash SAR Plan with a grant date fair value of
$12.00
per SAR, or
$4.1 million
, to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. All of these SARs contain a service condition and performance condition. The performance condition has been met.
The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the
nine months ended September 30,
2017
:
|
|
|
|
|
|
|
|
|
|
Grant Date Fair Value Assumptions
|
|
Expected term (in years)
|
|
4.24
|
|
|
Expected volatility
|
|
54.3
|
%
|
|
Risk-free interest rate
|
|
1.8
|
%
|
|
Dividend yield
|
|
—
|
%
|
Performance Shares.
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 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. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of
September 30, 2017
, unrecognized compensation costs related to unvested performance shares was
$2.7 million
and will be recognized over a weighted average period of
1.8
years.
The table below summarizes performance share activity for the
nine months ended September 30,
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target Performance Shares
(1)
|
|
Weighted Average Grant Date
Fair Value
|
|
For the Nine Months Ended September 30, 2017
|
|
|
|
|
|
Unvested performance shares, beginning of period
|
|
154,510
|
|
|
|
$58.44
|
|
|
Granted
|
|
46,787
|
|
|
|
$35.14
|
|
|
Vested
|
|
(56,342
|
)
|
|
|
$68.15
|
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
|
Unvested performance shares, end of period
|
|
144,955
|
|
|
|
$47.14
|
|
|
|
|
|
(1)
|
The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company
’
s final TSR ranking for the approximate three year performance period.
|
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
$35.14
per performance share, or
$1.6 million
, as part of its annual grant of long-term equity incentive awards. In addition to the market condition described above, the performance shares also contain a service condition and performance condition. The performance condition has been met. In addition, the Company issued
92,200
shares of common stock for
56,342
target performance shares that vested during the first quarter of 2017 with a multiplier of
164%
based on the Company’s final TSR ranking during the performance period.
The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the
nine months ended September 30,
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
|
|
—
|
%
|
Stock-Based Compensation Expense, Net.
Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash 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.
The Company recognized the following stock-based compensation expense, net for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
|
Restricted stock awards and units
|
|
|
$5,311
|
|
|
|
$5,487
|
|
|
|
$16,184
|
|
|
|
$23,079
|
|
|
Stock appreciation rights
|
|
429
|
|
|
3,361
|
|
|
(7,040
|
)
|
|
9,581
|
|
|
Performance shares
|
|
581
|
|
|
722
|
|
|
1,861
|
|
|
2,052
|
|
|
|
|
6,321
|
|
|
9,570
|
|
|
11,005
|
|
|
34,712
|
|
|
Less: amounts capitalized to oil and gas properties
|
|
(1,455
|
)
|
|
(1,150
|
)
|
|
(2,543
|
)
|
|
(3,878
|
)
|
|
Total stock-based compensation expense, net
|
|
|
$4,866
|
|
|
|
$8,420
|
|
|
|
$8,462
|
|
|
|
$30,834
|
|
10.
Derivative Instruments
Commodity 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, basis 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.
Basis Swaps:
The Company receives a variable NYMEX settlement price, plus or minus a fixed differential price, and pays a variable Argus published index price to the counterparties over specified periods for contracted volumes.
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. The Company has incurred premiums on certain of these contracts in order to obtain a higher floor price and/or ceiling price.
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 on a portion of the existing sold call options and therefore are presented on a net basis in the “Net Sold Call Options” table below.
Premiums
: In order to increase the fixed price on a portion of the Company's existing sold call options, as mentioned above, the Company incurred premiums on its purchased call options. Additionally, the Company has incurred premiums on certain of its three-way collars in order to obtain a higher floor price and/or ceiling price. The payment of premiums associated with the Company’s purchased call options and certain of the three-way collars are deferred until the applicable contracts settle on a monthly
basis. When the Company has entered into three-way collars which span multiple years, the Company has elected to defer payment of certain of the premiums until the final year's contracts settle on a monthly basis.
The following tables set forth a summary of the Company’s outstanding derivative positions at weighted average contract prices as of
September 30, 2017
:
Crude Oil Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in Bbls/d)
|
|
NYMEX Price ($/Bbl)
|
|
Q4 2017
|
|
15,000
|
|
|
|
$53.44
|
|
|
FY 2018
|
|
6,000
|
|
|
|
$49.55
|
|
Crude Oil Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in Bbls/d)
|
|
LLS-NYMEX Price Differential ($/Bbl)
|
|
December 2017
|
|
15,000
|
|
|
|
$4.13
|
|
|
FY 2018
|
|
6,000
|
|
|
|
$2.91
|
|
Crude Oil Three-Way Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Prices
|
|
Period
|
|
Volumes
(in Bbls/d)
|
|
Sub-Floor Price
($/Bbl)
|
|
Floor Price
($/Bbl)
|
|
Ceiling Price
($/Bbl)
|
|
FY 2018
|
|
18,000
|
|
|
|
$39.17
|
|
|
|
$49.08
|
|
|
|
$60.48
|
|
|
FY 2019
|
|
6,000
|
|
|
|
$40.00
|
|
|
|
$47.80
|
|
|
|
$61.45
|
|
Crude Oil Net Sold Call Options
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in Bbls/d)
|
|
NYMEX Ceiling Price ($/Bbl)
|
|
FY 2018
|
|
3,388
|
|
|
|
$71.33
|
|
|
FY 2019
|
|
3,875
|
|
|
|
$73.66
|
|
|
FY 2020
|
|
4,575
|
|
|
|
$75.98
|
|
Natural Gas Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in MMBtu/d)
|
|
NYMEX Price ($/MMBtu)
|
|
Q4 2017
|
|
20,000
|
|
|
|
$3.30
|
|
Natural Gas Sold Call Options
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in MMBtu/d)
|
|
NYMEX Ceiling Price ($/MMBtu)
|
|
Q4 2017
|
|
33,000
|
|
|
|
$3.00
|
|
|
FY 2018
|
|
33,000
|
|
|
|
$3.25
|
|
|
FY 2019
|
|
33,000
|
|
|
|
$3.25
|
|
|
FY 2020
|
|
33,000
|
|
|
|
$3.50
|
|
The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability 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 the Company’s 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 and its counterparty’s parent company, as applicable.
Contingent Consideration
The Company has entered into agreements containing contingent consideration that are, or will be, required to be bifurcated and accounted for separately as derivative instruments. The Company records the contingent consideration on its consolidated balance sheets measured at fair value with gains and losses as a result of changes in the fair value of the contingent consideration recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The cash flows resulting from payments due from the Company for settlement of contingent consideration, which will occur in January 2019 at the earliest, are classified as cash flows from financing activities for the portion of the payment up to the acquisition date fair value with any amounts paid in excess classified as cash flows from operating activities.
As part of the ExL Acquisition, the Company agreed to the Contingent ExL Payment that will require payment of
$50.0 million
per year for each of the years of 2018 through 2021, with a cap of
$125.0 million
, if the EIA WTI average price is greater than
$50.00
per barrel for the respective year. The Company determined that the Contingent ExL Payment was not clearly and closely related to the purchase and sale agreement for the ExL Properties, and therefore bifurcated this embedded feature and recorded this derivative at its acquisition date fair value of
$52.3 million
in the consolidated financial statements. As of
September 30, 2017
, the estimated fair value of the Contingent ExL Payment was
$60.3 million
and was classified as non-current “Derivative liabilities” in the consolidated balance sheets.
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 deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the Company’s consolidated balance sheets as of
September 30, 2017
and
December 31, 2016
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
|
(In thousands)
|
|
Commodity derivative instruments
|
|
|
$11,571
|
|
|
|
($8,757
|
)
|
|
|
$2,814
|
|
|
Deferred premium obligations
|
|
—
|
|
|
(879
|
)
|
|
(879
|
)
|
|
Other current assets
|
|
|
$11,571
|
|
|
|
($9,636
|
)
|
|
|
$1,935
|
|
|
Commodity derivative instruments
|
|
10,415
|
|
|
(9,867
|
)
|
|
548
|
|
|
Deferred premium obligations
|
|
—
|
|
|
(423
|
)
|
|
(423
|
)
|
|
Other assets-non current
|
|
|
$10,415
|
|
|
|
($10,290
|
)
|
|
|
$125
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($9,143
|
)
|
|
|
$8,757
|
|
|
|
($386
|
)
|
|
Deferred premium obligations
|
|
(7,271
|
)
|
|
879
|
|
|
(6,392
|
)
|
|
Derivative liabilities-current
|
|
|
($16,414
|
)
|
|
|
$9,636
|
|
|
|
($6,778
|
)
|
|
Commodity derivative instruments
|
|
(13,711
|
)
|
|
9,867
|
|
|
(3,844
|
)
|
|
Deferred premium obligations
|
|
(13,463
|
)
|
|
423
|
|
|
(13,040
|
)
|
|
Contingent ExL Payment
|
|
(60,300
|
)
|
|
—
|
|
|
(60,300
|
)
|
|
Derivative liabilities-non current
|
|
|
($87,474
|
)
|
|
|
$10,290
|
|
|
|
($77,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
|
(In thousands)
|
|
Commodity derivative instruments
|
|
|
$7,990
|
|
|
|
($6,753
|
)
|
|
|
$1,237
|
|
|
Deferred premium obligations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other current assets
|
|
|
$7,990
|
|
|
|
($6,753
|
)
|
|
|
$1,237
|
|
|
Commodity derivative instruments
|
|
3,882
|
|
|
(3,882
|
)
|
|
—
|
|
|
Deferred premium obligations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other assets-non current
|
|
|
$3,882
|
|
|
|
($3,882
|
)
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($27,346
|
)
|
|
|
$6,753
|
|
|
|
($20,593
|
)
|
|
Deferred premium obligations
|
|
(2,008
|
)
|
|
—
|
|
|
(2,008
|
)
|
|
Derivative liabilities-current
|
|
|
($29,354
|
)
|
|
|
$6,753
|
|
|
|
($22,601
|
)
|
|
Commodity derivative instruments
|
|
(28,841
|
)
|
|
3,882
|
|
|
(24,959
|
)
|
|
Deferred premium obligations
|
|
(2,569
|
)
|
|
—
|
|
|
(2,569
|
)
|
|
Contingent ExL Payment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Derivative liabilities-non current
|
|
|
($31,410
|
)
|
|
|
$3,882
|
|
|
|
($27,528
|
)
|
See “Note
11.
Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative instruments.
(Gain) Loss on Derivatives, Net
The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments and contingent consideration are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations on the Company’s consolidated statements of operations for the
three and nine months ended September 30,
2017
and
2016
is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
|
(Gain) Loss on Derivatives, Net
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$8,409
|
|
|
|
($8,309
|
)
|
|
|
($39,754
|
)
|
|
|
$12,006
|
|
|
Natural gas
|
|
(2,183
|
)
|
|
(3,490
|
)
|
|
(12,902
|
)
|
|
12,167
|
|
|
Deferred premium obligations incurred
|
|
10,151
|
|
|
55
|
|
|
17,652
|
|
|
5,765
|
|
|
Contingent ExL Payment
|
|
8,000
|
|
|
—
|
|
|
8,000
|
|
|
—
|
|
|
Total (Gain) Loss on Derivatives, Net
|
|
|
$24,377
|
|
|
|
($11,744
|
)
|
|
|
($27,004
|
)
|
|
|
$29,938
|
|
Cash Received (Paid) for Derivative Settlements, Net
Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as cash received (paid) for derivative settlements, net in the Company’s consolidated statements of cash flows. The effect of commodity derivative instruments and deferred premium obligations on the Company’s consolidated statements of cash flows for the
three and nine months ended September 30,
2017
and
2016
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
|
Cash Received (Paid) for Derivative Settlements, Net
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$6,500
|
|
|
|
$23,165
|
|
|
|
$9,941
|
|
|
|
$104,549
|
|
|
Natural gas
|
|
522
|
|
|
—
|
|
|
(731
|
)
|
|
—
|
|
|
Deferred premium obligations paid
|
|
(566
|
)
|
|
(2,808
|
)
|
|
(1,496
|
)
|
|
(5,729
|
)
|
|
Total Cash Received (Paid) for Derivative Settlements, Net
|
|
|
$6,456
|
|
|
|
$20,357
|
|
|
|
$7,714
|
|
|
|
$98,820
|
|
11.
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
September 30, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Derivative instrument assets
|
|
|
$—
|
|
|
|
$3,362
|
|
|
|
$—
|
|
|
Derivative instrument liabilities
|
|
|
$—
|
|
|
|
($4,230
|
)
|
|
|
($60,300
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Derivative instrument assets
|
|
|
$—
|
|
|
|
$1,237
|
|
|
|
$—
|
|
|
Derivative instrument liabilities
|
|
|
$—
|
|
|
|
($45,552
|
)
|
|
|
$—
|
|
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.
Commodity derivative instruments.
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 Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, 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
nine months ended September 30,
2017
and
2016
.
Contingent consideration.
The Company determined that the Contingent ExL Payment associated with the ExL Acquisition is an embedded derivative and is not clearly and closely related to the purchase and sale agreement for the ExL Properties. As a result, the Company bifurcated this embedded feature and reflected the liability at fair value in the consolidated financial statements. The fair value was determined by a third-party valuation specialist using a Monte Carlo simulation including significant inputs, such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuation, including the related inputs, and analyzed changes in fair value measurements between periods. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was a liability of
$60.3 million
and
$52.3 million
, respectively. As a result, the Company recorded a loss on the change in fair value of
$8.0 million
, which was classified as “(Gain) loss on derivatives, net” in the consolidated statements of operations. The Company had
no
transfers into or out of Level 3 for the
nine months ended September 30,
2017
and
2016
. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” and “Note
10.
Derivative Instruments” for further details of the contingent consideration.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured on a nonrecurring basis on the acquisition date by a third-party valuation specialist 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. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the assets acquired and liabilities assumed as of the acquisition dates for the ExL Acquisition and Sanchez Acquisition.
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.
The fair value measurements of the Preferred Stock are measured on a nonrecurring basis on the issuance date by a third-party valuation specialist 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 the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company.
See “Note
8.
Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants.
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 unamortized premiums and debt issuance costs, with the fair values measured using Level 1 inputs based on quoted secondary market trading prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
7.50% Senior Notes due 2020
|
|
|
$594,439
|
|
|
|
$610,500
|
|
|
|
$593,447
|
|
|
|
$624,750
|
|
|
6.25% Senior Notes due 2023
|
|
641,473
|
|
|
659,750
|
|
|
640,546
|
|
|
672,750
|
|
|
8.25% Senior Notes due 2025
|
|
245,502
|
|
|
269,375
|
|
|
—
|
|
|
—
|
|
|
Other long-term debt due 2028
|
|
4,425
|
|
|
4,408
|
|
|
4,425
|
|
|
4,419
|
|
12.
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.
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
$3,512,988
|
|
|
|
$89,589
|
|
|
|
$—
|
|
|
|
($3,499,850
|
)
|
|
|
$102,727
|
|
|
Total property and equipment, net
|
|
39,789
|
|
|
2,592,458
|
|
|
5,057
|
|
|
(3,986
|
)
|
|
2,633,318
|
|
|
Investment in subsidiaries
|
|
(1,097,703
|
)
|
|
—
|
|
|
—
|
|
|
1,097,703
|
|
|
—
|
|
|
Other assets
|
|
9,526
|
|
|
155
|
|
|
—
|
|
|
—
|
|
|
9,681
|
|
|
Total Assets
|
|
|
$2,464,600
|
|
|
|
$2,682,202
|
|
|
|
$5,057
|
|
|
|
($2,406,133
|
)
|
|
|
$2,745,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
$128,778
|
|
|
|
$3,687,474
|
|
|
|
$5,057
|
|
|
|
($3,502,870
|
)
|
|
|
$318,439
|
|
|
Long-term liabilities
|
|
1,716,898
|
|
|
92,431
|
|
|
—
|
|
|
15,879
|
|
|
1,825,208
|
|
|
Preferred stock
|
|
213,400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213,400
|
|
|
Total shareholders’ equity
|
|
405,524
|
|
|
(1,097,703
|
)
|
|
—
|
|
|
1,080,858
|
|
|
388,679
|
|
|
Total Liabilities and Shareholders’ Equity
|
|
|
$2,464,600
|
|
|
|
$2,682,202
|
|
|
|
$5,057
|
|
|
|
($2,406,133
|
)
|
|
|
$2,745,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
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
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Total revenues
|
|
|
$35
|
|
|
|
$181,244
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$181,279
|
|
|
Total costs and expenses
|
|
54,061
|
|
|
119,366
|
|
|
—
|
|
|
29
|
|
|
173,456
|
|
|
Income (loss) before income taxes
|
|
(54,026
|
)
|
|
61,878
|
|
|
—
|
|
|
(29
|
)
|
|
7,823
|
|
|
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in income of subsidiaries
|
|
61,878
|
|
|
—
|
|
|
—
|
|
|
(61,878
|
)
|
|
—
|
|
|
Net income
|
|
|
$7,852
|
|
|
|
$61,878
|
|
|
|
$—
|
|
|
|
($61,907
|
)
|
|
|
$7,823
|
|
|
Dividends on preferred stock
|
|
(2,249
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,249
|
)
|
|
Net income attributable to common shareholders
|
|
|
$5,603
|
|
|
|
$61,878
|
|
|
|
$—
|
|
|
|
($61,907
|
)
|
|
|
$5,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2016
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Total revenues
|
|
|
$105
|
|
|
|
$111,072
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$111,177
|
|
|
Total costs and expenses
|
|
28,551
|
|
|
184,047
|
|
|
—
|
|
|
66
|
|
|
212,664
|
|
|
Loss before income taxes
|
|
(28,446
|
)
|
|
(72,975
|
)
|
|
—
|
|
|
(66
|
)
|
|
(101,487
|
)
|
|
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
313
|
|
|
313
|
|
|
Equity in loss of subsidiaries
|
|
(72,975
|
)
|
|
—
|
|
|
—
|
|
|
72,975
|
|
|
—
|
|
|
Net loss
|
|
|
($101,421
|
)
|
|
|
($72,975
|
)
|
|
|
$—
|
|
|
|
$73,222
|
|
|
|
($101,174
|
)
|
|
Dividends on preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net loss attributable to common shareholders
|
|
|
($101,421
|
)
|
|
|
($72,975
|
)
|
|
|
$—
|
|
|
|
$73,222
|
|
|
|
($101,174
|
)
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Total revenues
|
|
|
$291
|
|
|
|
$498,826
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$499,117
|
|
|
Total costs and expenses
|
|
80,660
|
|
|
314,237
|
|
|
—
|
|
|
70
|
|
|
394,967
|
|
|
Income (loss) before income taxes
|
|
(80,369
|
)
|
|
184,589
|
|
|
—
|
|
|
(70
|
)
|
|
104,150
|
|
|
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in income of subsidiaries
|
|
184,589
|
|
|
—
|
|
|
—
|
|
|
(184,589
|
)
|
|
—
|
|
|
Net income
|
|
|
$104,220
|
|
|
|
$184,589
|
|
|
|
$—
|
|
|
|
($184,659
|
)
|
|
|
$104,150
|
|
|
Dividends on preferred stock
|
|
(2,249
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,249
|
)
|
|
Net income attributable to common shareholders
|
|
|
$101,971
|
|
|
|
$184,589
|
|
|
|
$—
|
|
|
|
($184,659
|
)
|
|
|
$101,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Total revenues
|
|
|
$349
|
|
|
|
$299,414
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$299,763
|
|
|
Total costs and expenses
|
|
151,445
|
|
|
822,582
|
|
|
—
|
|
|
431
|
|
|
974,458
|
|
|
Loss before income taxes
|
|
(151,096
|
)
|
|
(523,168
|
)
|
|
—
|
|
|
(431
|
)
|
|
(674,695
|
)
|
|
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in loss of subsidiaries
|
|
(523,168
|
)
|
|
—
|
|
|
—
|
|
|
523,168
|
|
|
—
|
|
|
Net loss
|
|
|
($674,264
|
)
|
|
|
($523,168
|
)
|
|
|
$—
|
|
|
|
$522,737
|
|
|
|
($674,695
|
)
|
|
Dividends on preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net loss attributable to common shareholders
|
|
|
($674,264
|
)
|
|
|
($523,168
|
)
|
|
|
$—
|
|
|
|
$522,737
|
|
|
|
($674,695
|
)
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Net cash provided by (used in) operating activities
|
|
|
($95,529
|
)
|
|
|
$376,126
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$280,597
|
|
|
Net cash used in investing activities
|
|
(728,833
|
)
|
|
(1,102,155
|
)
|
|
—
|
|
|
726,029
|
|
|
(1,104,959
|
)
|
|
Net cash provided by financing activities
|
|
825,260
|
|
|
726,029
|
|
|
—
|
|
|
(726,029
|
)
|
|
825,260
|
|
|
Net increase in cash and cash equivalents
|
|
898
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
898
|
|
|
Cash and cash equivalents, beginning of period
|
|
4,194
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,194
|
|
|
Cash and cash equivalents, end of period
|
|
|
$5,092
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$5,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Net cash provided by (used in) operating activities
|
|
|
($10,882
|
)
|
|
|
$208,729
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$197,847
|
|
|
Net cash used in investing activities
|
|
(122,846
|
)
|
|
(331,351
|
)
|
|
(740
|
)
|
|
123,362
|
|
|
(331,575
|
)
|
|
Net cash provided by financing activities
|
|
94,045
|
|
|
122,622
|
|
|
740
|
|
|
(123,362
|
)
|
|
94,045
|
|
|
Net decrease in cash and cash equivalents
|
|
(39,683
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39,683
|
)
|
|
Cash and cash equivalents, beginning of period
|
|
42,918
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42,918
|
|
|
Cash and cash equivalents, end of period
|
|
|
$3,235
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$3,235
|
|
13.
Supplemental Cash Flow Information
Supplemental cash flow disclosures and non-cash investing activities are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
|
Supplemental cash flow disclosures:
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
|
$59,389
|
|
|
|
$55,808
|
|
|
|
|
|
|
|
|
Non-cash investing activities:
|
|
|
|
|
|
Increase (decrease) in capital expenditure payables and accruals
|
|
|
$98,829
|
|
|
|
$7,316
|
|
|
Contingent ExL Payment
|
|
52,300
|
|
|
—
|
|
|
Stock-based compensation expense capitalized to oil and gas properties
|
|
2,543
|
|
|
3,878
|
|
|
Asset retirement obligations capitalized to oil and gas properties
|
|
2,761
|
|
|
766
|
|
14.
Subsequent Events
Potential Divestiture of Marcellus Assets
On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of
$84.0 million
, subject to customary purchase price adjustments. The transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. On October 5, 2017, the buyer paid
$6.3 million
into escrow as a deposit.
The Company could also receive contingent consideration of
$3.0 million
per year if the average settlement prices of a MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc. (the “CME HH average price”) is above
$3.13
,
$3.18
, and
$3.30
for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively. This conditional consideration will be
zero
for the respective year if such CME HH average price of a MMBtu of Henry Hub natural gas is at or below the per MMBtu amounts listed above for any of such years, and is capped at
$7.5 million
.
Simultaneous with the signing of the Marcellus Shale transaction discussed above, the Company’s existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture will be assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture will terminate except for limited post-closing obligations.
Hedging
In October and November 2017, the Company entered into the following crude oil derivative positions at weighted average contract prices:
Crude Oil Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volumes (in Bbls/d)
|
|
Midland-NYMEX Price Differential ($/Bbl)
|
|
FY 2018
|
|
6,000
|
|
|
|
($0.10
|
)
|
Crude Oil Three-Way Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Prices
|
|
Period
|
|
Volumes
(in Bbls/d)
|
|
Sub-Floor Price
($/Bbl)
|
|
Floor Price
($/Bbl)
|
|
Ceiling Price
($/Bbl)
|
|
FY 2018
|
|
6,000
|
|
|
|
$40.00
|
|
|
|
$49.00
|
|
|
|
$59.13
|
|
|
FY 2019
|
|
6,000
|
|
|
|
$40.00
|
|
|
|
$49.00
|
|
|
|
$59.14
|
|
Eleventh Amendment to the Credit Agreement
On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at
$900.0 million
, with an elected commitment amount of
$800.0 million
, until the next redetermination thereof, (ii) increase the general basket available for restricted payments from
$50.0 million
to
$75.0 million
and (iii) amend certain other provisions, in each case as set forth therein. The calculation of the borrowing base was supported solely by the reserves of the Company's Eagle Ford and Delaware Basin assets.