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 natural gas from resource plays 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, 2017
(“
2017
Annual Report”).
2.
Summary of Significant Accounting Policies
Recently Adopted Accounting Standards
Revenue From Contracts with Customers
. Effective January 1, 2018, the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASC 606”) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the three and nine months ended September 30, 2017 has not been recast and continues to be reported under the accounting standards in effect for that period. Additionally, adoption of ASC 606 did not impact net income attributable to common shareholders and the Company does not expect that it will do so in future periods.
The tables below summarize the impact of adoption for the
three and nine months ended September 30,
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
|
Under ASC 606
|
|
Under ASC 605
|
|
Increase
|
|
% Increase
|
|
|
(In thousands)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$254,525
|
|
|
|
$254,382
|
|
|
|
$143
|
|
|
0.1
|
%
|
Natural gas liquids
|
|
33,798
|
|
|
32,018
|
|
|
1,780
|
|
|
5.6
|
%
|
Natural gas
|
|
15,052
|
|
|
14,280
|
|
|
772
|
|
|
5.4
|
%
|
Total revenues
|
|
303,375
|
|
|
300,680
|
|
|
2,695
|
|
|
0.9
|
%
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
Lease operating
|
|
41,022
|
|
|
38,327
|
|
|
2,695
|
|
|
7.0
|
%
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
$82,226
|
|
|
|
$82,226
|
|
|
|
$—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Under ASC 606
|
|
Under ASC 605
|
|
Increase
|
|
% Increase
|
|
|
(In thousands)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$679,242
|
|
|
|
$678,834
|
|
|
|
$408
|
|
|
0.1
|
%
|
Natural gas liquids
|
|
71,969
|
|
|
68,253
|
|
|
3,716
|
|
|
5.4
|
%
|
Natural gas
|
|
41,417
|
|
|
39,439
|
|
|
1,978
|
|
|
5.0
|
%
|
Total revenues
|
|
792,628
|
|
|
786,526
|
|
|
6,102
|
|
|
0.8
|
%
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
Lease operating
|
|
115,446
|
|
|
109,344
|
|
|
6,102
|
|
|
5.6
|
%
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
$145,829
|
|
|
|
$145,829
|
|
|
|
$—
|
|
|
—
|
%
|
Changes to crude oil, NGL, and natural gas revenues and lease operating expense are due to the conclusion that the Company controls the product throughout processing before transferring to the customer for certain natural gas processing arrangements. Therefore, any transportation, gathering, and processing fees incurred prior to transfer of control are included in lease operating expense.
Business Combinations.
In January 2017, the Financial Accounting Standards Board (“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 divestitures) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01 using the prospective method and will apply the clarified definition of a business to future acquisitions and divestitures.
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. Effective January 1, 2018, the Company adopted ASU 2016-15 using the retrospective approach as prescribed by ASU 2016-15. There were no changes to the statement of cash flows as a result of adoption.
Recently Issued Accounting Pronouncements
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 (“ROU”) asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. 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 in the process of reviewing and determining the contracts to which ASU 2016-02 applies with the assistance of a third party consultant. These include contracts such as non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, and contracts for the use of vehicles and well equipment. The Company continues to review current accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities due to the required recognition of ROU assets and corresponding lease liabilities, (ii) increases in depreciation, depletion and amortization and interest expense, (iii) decreases in lease operating and general and administrative expense and (iv) additional disclosures, however, the full impact to the Company’s consolidated financial statements and related disclosures is still being evaluated. Currently, the Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements, and not to recognize ROU assets or lease liabilities for short-term leases. The Company plans to adopt the guidance on the effective date of January 1, 2019. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.
Revenue Recognition
The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of
September 30, 2018
and
December 31, 2017
, receivables from contracts with customers were
$100.2 million
and
$85.6 million
, respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of income.
Crude oil sales.
Crude oil production is primarily sold at the wellhead at an agreed upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead, net of transportation costs incurred by the purchaser.
Natural gas and NGL sales.
Natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company evaluates whether it is the principal or agent in the transaction and has concluded it is the principal and the purchasers of the NGLs and residue gas are the customers. Revenue is recognized on a gross basis, with gathering, processing and transportation fees recognized as lease operating expense in the consolidated statements of income as the Company maintains control throughout processing.
Transaction Price Allocated to Remaining Performance Obligations
. The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Net Income Attributable to Common Shareholders Per Common Share
The following table summarizes the calculation of net income attributable to common shareholders per common share:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands, except
per share amounts)
|
Net Income
|
|
|
$81,346
|
|
|
|
$7,823
|
|
|
|
$144,147
|
|
|
|
$104,150
|
|
Dividends on preferred stock
|
|
(4,457
|
)
|
|
(2,249
|
)
|
|
(13,794
|
)
|
|
(2,249
|
)
|
Accretion on preferred stock
|
|
(771
|
)
|
|
—
|
|
|
(2,264
|
)
|
|
—
|
|
Loss on redemption of preferred stock
|
|
—
|
|
|
—
|
|
|
(7,133
|
)
|
|
—
|
|
Net Income Attributable to Common Shareholders
|
|
|
$76,118
|
|
|
|
$5,574
|
|
|
|
$120,956
|
|
|
|
$101,901
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average common shares outstanding
|
|
86,727
|
|
|
81,053
|
|
|
83,461
|
|
|
70,728
|
|
Dilutive effect of restricted stock and performance shares
|
|
1,272
|
|
|
85
|
|
|
967
|
|
|
253
|
|
Dilutive effect of common stock warrants
|
|
1,040
|
|
|
—
|
|
|
793
|
|
|
166
|
|
Diluted weighted average common shares outstanding
|
|
89,039
|
|
|
81,138
|
|
|
85,221
|
|
|
71,147
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Common Shareholders Per Common Share
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$0.88
|
|
|
|
$0.07
|
|
|
|
$1.45
|
|
|
|
$1.44
|
|
Diluted
|
|
|
$0.85
|
|
|
|
$0.07
|
|
|
|
$1.42
|
|
|
|
$1.43
|
|
The computation of diluted net income attributable to common shareholders per common share excluded restricted stock, performance shares and common stock warrants that were anti-dilutive. The following table presents the weighted average anti-dilutive securities for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Anti-dilutive restricted stock and performance shares
|
|
—
|
|
|
730
|
|
|
5
|
|
|
120
|
|
Anti-dilutive common stock warrants
|
|
—
|
|
|
152
|
|
|
—
|
|
|
—
|
|
Total weighted average anti-dilutive securities
|
|
—
|
|
|
882
|
|
|
5
|
|
|
120
|
|
3.
Acquisitions and Divestitures of Oil and Gas Properties
2018 Acquisitions and Divestitures
Devon Acquisition.
On August 13, 2018, the Company entered into a purchase and sale agreement with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas (the “Devon Properties”) for an agreed upon price of
$215.0 million
, with an effective date of April 1, 2018, subject to customary purchase price adjustments (the “Devon Acquisition”). The Company paid
$21.5 million
as a deposit on August 13, 2018 and
$183.4 million
upon initial closing on October 17, 2018, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date, for an estimated aggregate purchase price of
$204.9 million
. The final purchase price remains subject to post-closing adjustments.
Under one of the Company’s existing joint operating agreements covering acreage in the vicinity of the Devon Properties, the other party to the joint operating agreement has a right to purchase a
20%
interest in certain of the acres within the Devon Properties acquired by the Company at a price based on the Company’s cost to acquire the Devon Properties. This right is exercisable for a 30-day period after the Company delivers a specified notice following the closing of the Devon Acquisition and, if not exercised, will expire in the fourth quarter of 2018. To the extent that the other party exercises its right to make such purchase, the Company’s interests in the Devon Properties will be reduced and the proceeds received will be recognized as a reduction of proved oil and gas properties.
The Company funded the Devon Acquisition with net proceeds from the common stock offering completed on August 17, 2018, which, pending the closing of the Devon Acquisition, were used to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note
9.
Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering.
The Devon Acquisition will be accounted for as a business combination. The Company has not completed its initial allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated acquisition date fair values. The Company will disclose the allocation of the purchase price as well as other related disclosures in its Annual Report on Form 10-K for the year ended December 31, 2018.
Delaware Basin Divestiture.
On July 11, 2018, the Company closed on the divestiture of certain non-operated assets in the Delaware Basin for an agreed upon price of
$30.0 million
, with an effective date of May 1, 2018, subject to customary purchase price adjustments. The Company received
$31.4 million
upon closing on July 11, 2018 and paid
$0.5 million
upon post-closing on October 22, 2018, for aggregate net proceeds of
$30.9 million
.
Eagle Ford Divestiture.
On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of
$245.0 million
, with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. The Company received
$24.5 million
as a deposit on December 11, 2017,
$211.7 million
upon closing on January 31, 2018,
$10.0 million
for leases that were not conveyed at closing on February 16, 2018, and paid
$0.5 million
upon post-closing on July 19, 2018, for aggregate net proceeds of
$245.7 million
.
Niobrara Divestiture.
On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of
$140.0 million
, with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received
$14.0 million
as a deposit on November 20, 2017,
$122.6 million
upon closing on January 19, 2018, and paid
$1.0 million
upon post-closing on August 14, 2018, for aggregate net proceeds of
$135.6 million
. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
The aggregate net proceeds for each of the 2018 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized.
2017 Acquisitions and Divestitures
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. to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward counties, Texas for an agreed upon price of
$648.0 million
, with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid
$75.0 million
as a deposit on June 28, 2017,
$601.0 million
upon closing on August 10, 2017, and
$3.8 million
upon post-closing on December 8, 2017 for aggregate cash consideration of
$679.8 million
, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. As part of the ExL Acquisition, the Company agreed to a contingent consideration arrangement (the “Contingent ExL Consideration”), which was determined to be an embedded derivative. As a result, the liability is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
The ExL Acquisition was accounted for as a business combination, therefore, 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 forward oil and gas price curves, 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 Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included forward oil and gas price curves, volatility factors, and a risk adjusted discount rate. See “Note
11.
Fair Value Measurements” for further details.
The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
|
|
|
|
|
|
|
|
Purchase Price Allocation
|
|
|
(In thousands)
|
Assets
|
|
|
Other current assets
|
|
|
$106
|
|
Oil and gas properties
|
|
|
Proved properties
|
|
294,754
|
|
Unproved properties
|
|
443,194
|
|
Total oil and gas properties
|
|
|
$737,948
|
|
Total assets acquired
|
|
|
$738,054
|
|
|
|
|
Liabilities
|
|
|
Revenues and royalties payable
|
|
|
$5,785
|
|
Asset retirement obligations
|
|
153
|
|
Contingent ExL Consideration
|
|
52,300
|
|
Total liabilities assumed
|
|
|
$58,238
|
|
Net Assets Acquired
|
|
|
$679,816
|
|
The results of operations for the ExL Acquisition have been included in the Company’s consolidated statements of income since the August 10, 2017 closing date, including total revenues and net income attributable to common shareholders for the three and nine months ended September 30, 2018 and 2017 as shown in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Total revenues
|
|
|
$71,525
|
|
|
|
$14,016
|
|
|
|
$167,764
|
|
|
|
$14,016
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Common Shareholders
|
|
|
$57,466
|
|
|
|
$11,393
|
|
|
|
$134,317
|
|
|
|
$11,393
|
|
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 months ended September 30, 2017, 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.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Nine Months Ended September 30, 2017
|
|
|
(In thousands, except per share amounts)
|
Total revenues
|
|
|
$189,499
|
|
|
|
$534,607
|
|
Net Income Attributable to Common Shareholders
|
|
|
$14,654
|
|
|
|
$115,053
|
|
|
|
|
|
|
Net Income Attributable to Common Shareholders Per Common Share
|
|
|
|
|
Basic
|
|
|
$0.18
|
|
|
|
$1.63
|
|
Diluted
|
|
|
$0.18
|
|
|
|
$1.62
|
|
Marcellus Divestiture.
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
. The Company received
$6.3 million
into escrow as a deposit on October 5, 2017 and
$67.6 million
upon closing on November 21, 2017, for aggregate net proceeds of
$73.9 million
. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Marcellus Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the
fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
Effective August 2008, the Company’s wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates, “Avista”). There have been no revenues, expenses, or operating cash flows in the Avista Marcellus joint venture during the years ended December 31, 2015, 2016 and 2017 or during the
nine months ended September 30,
2018
. The Avista Marcellus joint venture agreements terminated during the third quarter of 2018 in connection with the sale of the remaining immaterial assets.
Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP. ACP II’s Board of Managers has the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of ACP II’s Board of Managers. The terms of the Avista Marcellus joint venture were approved by a special committee of the Company’s independent directors.
Utica Divestiture
. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale for an agreed upon price of
$62.0 million
. The Company received
$6.2 million
as a deposit on August 31, 2017,
$54.4 million
upon closing on November 15, 2017, and
$2.5 million
upon post-closing on December 28, 2017, for aggregate net proceeds of
$63.1 million
. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Utica Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note
10.
Derivative Instruments” and “Note
11.
Fair Value Measurements” for further details.
Delaware Basin Divestiture.
During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for aggregate net proceeds of
$15.3 million
.
The aggregate net proceeds for each of the 2017 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized.
2016 Acquisitions and Divestitures
Sanchez Acquisition.
On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale for an agreed upon price of
$181.0 million
, with an effective date of June 1, 2016, subject to customary purchase price adjustments. The Company paid
$10.0 million
as a deposit on October 24, 2016,
$143.5 million
upon initial closing on December 14, 2016, and
$7.0 million
and
$9.8 million
on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of initial closing, for aggregate cash consideration of
$170.3 million
, which included purchase price adjustments primarily related to the net cash flows from the effect date to the closing date.
The Company did not have any material divestitures in 2016.
4.
Property and Equipment, Net
As of
September 30, 2018
and
December 31, 2017
, total property and equipment, net consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
|
(In thousands)
|
Oil and gas properties, full cost method
|
|
|
|
|
Proved properties
|
|
|
$5,988,301
|
|
|
|
$5,615,153
|
|
Accumulated depreciation, depletion and amortization and impairments
|
|
(3,863,534
|
)
|
|
(3,649,806
|
)
|
Proved properties, net
|
|
2,124,767
|
|
|
1,965,347
|
|
Unproved properties, not being amortized
|
|
|
|
|
Unevaluated leasehold and seismic costs
|
|
516,537
|
|
|
612,589
|
|
Capitalized interest
|
|
62,738
|
|
|
47,698
|
|
Total unproved properties, not being amortized
|
|
579,275
|
|
|
660,287
|
|
Other property and equipment
|
|
28,134
|
|
|
25,625
|
|
Accumulated depreciation
|
|
(17,249
|
)
|
|
(15,449
|
)
|
Other property and equipment, net
|
|
10,885
|
|
|
10,176
|
|
Total property and equipment, net
|
|
|
$2,714,927
|
|
|
|
$2,635,810
|
|
Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was
$13.29
and
$13.04
for the
three months ended September 30,
2018
and
2017
, respectively, and
$13.57
and
$12.73
for the
nine months ended September 30,
2018
and
2017
, respectively.
The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling
$2.9 million
and
$3.3 million
for the
three months ended September 30,
2018
and
2017
, respectively, and
$15.6 million
and
$10.6 million
for the
nine months ended September 30,
2018
and
2017
, 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
for the
three months ended September 30,
2018
and
2017
and
$27.6 million
and
$16.2 million
for the
nine months ended September 30,
2018
and
2017
, respectively.
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, excluding significant unusual or infrequent items, the tax effects of statutory rate changes, certain changes in the assessment of the realizability of deferred tax assets, and excess tax benefits or deficiencies related to the vesting of stock-based compensation awards, which are recognized as discrete items in the interim period in which they occur.
The Company’s income tax expense differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of
21%
for the
three and nine months ended September 30,
2018 and
35%
for the
three and nine months ended September 30,
2017, to income before income taxes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Income before income taxes
|
|
|
$82,226
|
|
|
|
$7,823
|
|
|
|
$145,829
|
|
|
|
$104,150
|
|
Income tax expense at the U.S. federal statutory rate
|
|
(17,267
|
)
|
|
(2,738
|
)
|
|
(30,624
|
)
|
|
(36,452
|
)
|
State income tax expense, net of U.S. federal income tax benefit
|
|
(881
|
)
|
|
(247
|
)
|
|
(1,687
|
)
|
|
(1,974
|
)
|
Tax deficiencies related to stock-based compensation
|
|
(10
|
)
|
|
(273
|
)
|
|
(2,552
|
)
|
|
(3,029
|
)
|
Decrease in valuation allowance due to current period activity
|
|
17,400
|
|
|
3,253
|
|
|
33,849
|
|
|
41,570
|
|
Other
|
|
(122
|
)
|
|
5
|
|
|
(668
|
)
|
|
(115
|
)
|
Income tax expense
|
|
|
($880
|
)
|
|
|
$—
|
|
|
|
($1,682
|
)
|
|
|
$—
|
|
Tax Cuts and Jobs Act
On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the U.S. federal statutory corporate income tax rate to
21%
from
35%
beginning January 1, 2018. Due to the uncertainty regarding the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 which allowed the Company to provide a provisional estimate of the impacts of the Act in earnings for the year ended December 31, 2017 and also provided a one-year measurement period in which the Company would record additional impacts from the enactment of the Act as they are identified. In August 2018, the Internal Revenue Service issued Notice 2018-68, Guidance on the Application of Section 162(m) (“Notice 2018-68”), which provides initial guidance on the application of Section 162(m), as amended. Notice 2018-68 provided guidance regarding the group of covered employees subject to Section 162(m)’s deduction limit under the Act and the scope of transition relief available under the Act. The Company is currently evaluating the impact of Notice 2018-68, but as of
September 30, 2018
, has not made any changes to the provisional estimate recorded in earnings for the year ended December 31, 2017. While the Company has made a reasonable estimate of the effects on its existing deferred tax balances, it has not completed its accounting for the tax effects of the enactment of the Act and will continue to monitor provisions with discrete rate impacts and additional guidance provided within the one year measurement period.
Deferred Tax Asset Valuation Allowance
The deferred tax asset valuation allowance was
$299.1 million
and
$333.0 million
as of September 30, 2018 and December 31, 2017, respectively. Decreases in the valuation allowance for the three months and nine months ended September 30, 2018 and 2017 were based primarily on the pre-tax income recorded during those periods.
Throughout 2017 and the first nine months of 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that
the deferred tax assets would not be realized. The Company intends to maintain a full valuation allowance against its deferred tax assets until there is sufficient evidence to support the reversal of such valuation allowance.
6.
Long-Term Debt
Long-term debt consisted of the following as of
September 30, 2018
and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
|
(In thousands)
|
Senior Secured Revolving Credit Facility due 2022
|
|
|
$309,837
|
|
|
|
$291,300
|
|
7.50% Senior Notes due 2020
|
|
130,000
|
|
|
450,000
|
|
Unamortized premium for 7.50% Senior Notes
|
|
124
|
|
|
579
|
|
Unamortized debt issuance costs for 7.50% Senior Notes
|
|
(980
|
)
|
|
(4,492
|
)
|
6.25% Senior Notes due 2023
|
|
650,000
|
|
|
650,000
|
|
Unamortized debt issuance costs for 6.25% Senior Notes
|
|
(7,219
|
)
|
|
(8,208
|
)
|
8.25% Senior Notes due 2025
|
|
250,000
|
|
|
250,000
|
|
Unamortized debt issuance costs for 8.25% Senior Notes
|
|
(4,073
|
)
|
|
(4,395
|
)
|
Other long-term debt due 2028
|
|
—
|
|
|
4,425
|
|
Long-term debt
|
|
|
$1,327,689
|
|
|
|
$1,629,209
|
|
Senior Secured Revolving Credit Facility
The Company has a senior secured revolving credit facility with a syndicate of banks that, as of
September 30, 2018
, had a borrowing base of
$1.0 billion
, with an elected commitment amount of
$900.0 million
, and borrowings outstanding of
$309.8 million
at a weighted average interest rate of
3.87%
. 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 due 2020 (the “
7.50%
Senior Notes”) have not been redeemed or refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. See “Note
14.
Subsequent Events” for details regarding the maturity date of the credit agreement upon redemption of the remaining
$130.0 million
outstanding aggregate principal amount of its
7.50%
Senior Notes. 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 January 31, 2018, as a result of the Eagle Ford divestiture, the Company’s borrowing base under the senior secured revolving credit facility was reduced from
$900.0 million
to
$830.0 million
, however, the elected commitment amount remained unchanged at
$800.0 million
. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for details of the Eagle Ford divestiture.
On May 4, 2018, the Company entered into the twelfth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at
$1.0 billion
, with an elected commitment amount of
$900.0 million
, until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from
2.00%
-
3.00%
to
1.50%
-
2.50%
and base rate loans from
1.00%
-
2.00%
to
0.50%
-
1.50%
, each depending on level of facility usage, (iii) amend the covenant limiting payment of dividends and distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv) amend certain other provisions, in each case as set forth therein.
On October 29, 2018, the Company entered into the thirteenth amendment to its credit agreement governing the revolving credit facility. See “Note
14.
Subsequent Events” for further details of the thirteenth amendment.
The obligations of the Company under the credit agreement are guaranteed by the Company’s material 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 income.
|
|
|
|
|
|
|
|
Ratio of Outstanding Borrowings to Lender Commitments
|
|
Applicable Margin for
Base Rate Loans
|
|
Applicable Margin for
Eurodollar Loans
|
|
Commitment Fee
|
Less than 25%
|
|
0.50%
|
|
1.50%
|
|
0.375%
|
Greater than or equal to 25% but less than 50%
|
|
0.75%
|
|
1.75%
|
|
0.375%
|
Greater than or equal to 50% but less than 75%
|
|
1.00%
|
|
2.00%
|
|
0.500%
|
Greater than or equal to 75% but less than 90%
|
|
1.25%
|
|
2.25%
|
|
0.500%
|
Greater than or equal to 90%
|
|
1.50%
|
|
2.50%
|
|
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 premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA will be calculated based on the last four fiscal quarters after giving pro forma effect to EBITDA for material acquisitions and divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of
September 30, 2018
, the ratio of Total Debt to EBITDA was
1.95
to 1.00 and the Current Ratio was
1.84
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).
Redemptions of 7.50% Senior Notes
During the first quarter of 2018, the Company redeemed
$320.0 million
of the outstanding aggregate principal amount of its
7.50%
Senior Notes at a price equal to
101.875%
of par. Upon the redemptions, the Company paid
$336.9 million
, which included redemption premiums of
$6.0 million
and accrued and unpaid interest of
$10.9 million
. The redemptions were funded primarily from the net proceeds received from the divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of these divestitures. As a result of the redemptions, the Company recorded a loss on extinguishment of debt of
$8.7 million
, which included the redemption premiums of
$6.0 million
and the write-off of associated unamortized premiums and debt issuance costs of
$2.7 million
.
See “Note
14.
Subsequent Events” for details of the notice of conditional redemption for the remaining
$130.0 million
outstanding aggregate principal amount of its
7.50%
Senior Notes.
Redemption of Other Long-Term Debt
On May 3, 2018, the Company redeemed the remaining
$4.4 million
outstanding aggregate principal amount of its
4.375%
Convertible Senior Notes due 2028 at a price equal to
100%
of par. Upon the redemption, the Company paid
$4.5 million
, which included accrued and unpaid interest of
$0.1 million
.
Issuance of 8.25% Senior Notes
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 Company used the proceeds of
$245.4 million
, net of underwriting discounts and commissions and offering costs, to fund a portion 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.
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, tax changes, 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 and Common Stock Warrants
On August 10, 2017, the Company closed on the issuance and sale in a private placement of (i)
$250.0 million
initial liquidation preference (
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, to certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”). The closing of the private placement occurred on August 10, 2017, contemporaneously with the closing of the ExL Acquisition. The Company used the proceeds of approximately $236.4 million, net of issuance costs, to fund a portion of the ExL Acquisition and for general corporate purposes.
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 preferred stock dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending:
|
|
|
|
|
Period
|
|
Percentage
|
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 had the right to 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 is presented as temporary equity in the consolidated balance sheets with the issuance date fair value accreted to the initial liquidation preference using the effective interest method.
The table below presents the reconciliation of changes in the carrying amount of Preferred Stock for the
nine months ended September 30,
2018
:
|
|
|
|
|
|
|
|
Carrying Amount of Preferred Stock
|
|
|
(In thousands)
|
December 31, 2017
|
|
|
$214,262
|
|
Redemption of Preferred Stock
|
|
(42,897
|
)
|
Accretion on Preferred Stock
|
|
2,264
|
|
September 30, 2018
|
|
|
$173,629
|
|
Loss on Redemption of Preferred Stock
During the first quarter of 2018, the Company redeemed
50,000
shares of Preferred Stock, representing
20%
of the issued and outstanding Preferred Stock, for
$50.5 million
, consisting of the
$50.0 million
redemption price and
$0.5 million
accrued and unpaid dividends. The Company recognized a
$7.1 million
loss on the redemption due to the excess of the
$50.0 million
redemption price over the
$42.9 million
redemption date carrying value of the Preferred Stock.
9.
Shareholders’ Equity and Stock-Based Compensation
Sales of Common Stock
On August 17, 2018, the Company completed a public offering of
9.5 million
shares of its common stock at a price per share of
$22.55
. The Company used the proceeds of
$213.9 million
, net of offering costs, to fund the Devon Acquisition and for general corporate purposes. Pending the closing of the Devon Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for further details of the Devon Acquisition.
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 proceeds of
$222.4 million
, net of offering costs, to fund a portion 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
The Company grants equity-based incentive awards under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”) and the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The 2017 Incentive Plan replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”) and, 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. Under the 2017 Incentive Plan, the Company may grant restricted stock awards and units, stock appreciation rights that can be settled in cash or shares of common stock, performance shares, and stock options to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Company may grant stock appreciation rights that may only be settled in cash to employees and independent contractors.
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 at the effective date of the 2017 Incentive Plan, may be granted (the “Maximum Share Limit”). Each restricted stock award and unit and performance share granted under the 2017 Incentive Plan counts as
1.35
shares against the Maximum Share Limit. Each stock option and stock appreciation right to be settled in shares of common stock granted under the 2017 Incentive Plan counts as
1.00
share against the Maximum Share Limit. Stock appreciation rights to be settled in cash granted under the 2017 Incentive Plan and stock appreciation rights granted under the Cash SAR Plan (collectively, “Cash SARs”) do not count against the Maximum Share Limit. Restricted stock awards and units, performance shares, and Cash SARs activity during the nine months ended September 30, 2018 is presented below. The Company has not granted stock appreciation rights to be settled in shares of common stock and has no outstanding stock options. As of
September 30, 2018
, there were
296,654
shares of common stock available for grant under the 2017 Incentive Plan.
Restricted Stock Awards and Units
The table below summarizes restricted stock award and unit activity for the
nine months ended September 30,
2018
:
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
Unvested restricted stock awards and units, beginning of period
|
|
1,482,655
|
|
|
|
$28.07
|
|
Granted
|
|
1,391,422
|
|
|
|
$15.07
|
|
Vested
|
|
(615,762
|
)
|
|
|
$31.44
|
|
Forfeited
|
|
(23,880
|
)
|
|
|
$18.51
|
|
Unvested restricted stock awards and units, end of period
|
|
2,234,435
|
|
|
|
$19.14
|
|
During the
nine months ended September 30,
2018
, the Company granted
1,391,422
restricted stock awards and units primarily consisting of
1,343,412
restricted stock units to employees and independent contractors as part of its annual grant of long-term equity incentive awards during the first quarter of 2018. These restricted stock units had a grant date fair value of
$19.7 million
and vest ratably over an approximate
three
-year period. During the third quarter of 2018, the Company granted
33,536
restricted stock units to its non-employee directors, which had a grant date fair value of
$0.9 million
and will vest on the earlier of the date of the 2019 Annual Meeting of Shareholders and June 30, 2019.
As of
September 30, 2018
, unrecognized compensation costs related to unvested restricted stock awards and units were
$26.8 million
and will be recognized over a weighted average period of
2.0
years.
Cash SARs
The table below summarizes the Cash SAR activity for the
nine months ended September 30,
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash SARs
|
|
Weighted
Average
Exercise
Prices
|
|
Weighted Average Remaining Life
(In years)
|
|
Aggregate Intrinsic Value
(In millions)
|
|
Aggregate Intrinsic Value of Exercises
(In millions)
|
Outstanding, beginning of period
|
|
714,238
|
|
|
|
$27.12
|
|
|
|
|
|
|
|
Granted
|
|
616,686
|
|
|
|
$14.67
|
|
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
|
$—
|
|
|
|
|
|
|
|
$—
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
|
|
|
|
|
|
Expired
|
|
—
|
|
|
|
$—
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
1,330,924
|
|
|
|
$21.35
|
|
|
4.6
|
|
|
$6.5
|
|
|
|
Vested, end of period
|
|
543,018
|
|
|
|
$27.18
|
|
|
|
|
|
|
|
Vested and exercisable, end of period
|
|
—
|
|
|
|
$27.18
|
|
|
2.8
|
|
|
$—
|
|
|
|
During the
nine months ended September 30,
2018
, the Company granted
616,686
Cash SARs to certain employees and independent contractors, all of which occurred in the first quarter of 2018 as part of the Company’s annual grant of long-term equity incentive awards. These Cash SARs vest ratably over an approximate
three
-year period and expire approximately
seven
years from the grant date.
The grant date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was
$4.9 million
. The following table summarizes the assumptions used to calculate the grant date fair value of the Cash SARs granted during the
nine months ended September 30,
2018
:
|
|
|
|
|
|
|
Grant Date Fair Value Assumptions
|
Expected term (in years)
|
|
6.0
|
|
Expected volatility
|
|
54.3
|
%
|
Risk-free interest rate
|
|
2.8
|
%
|
Dividend yield
|
|
—
|
%
|
The liability for Cash SARs as of
September 30, 2018
was
$7.9 million
, all of which was classified as “Other current liabilities,” in the consolidated balance sheets. As of
December 31, 2017
, the liability for Cash SARs was
$4.4 million
, all of which was classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested Cash SARs were
$8.7 million
as of
September 30, 2018
, and will be recognized over a weighted average period of
2.4
years.
Performance Shares
The table below summarizes performance share activity for the
nine months ended September 30,
2018
:
|
|
|
|
|
|
|
|
|
|
|
Target Performance Shares
(1)
|
|
Weighted Average Grant Date
Fair Value
|
Unvested performance shares, beginning of period
|
|
144,955
|
|
|
|
$47.14
|
|
Granted
|
|
93,771
|
|
|
|
$19.09
|
|
Vested at end of performance period
|
|
(49,458
|
)
|
|
|
$65.51
|
|
Did not vest at end of performance period
|
|
(7,059
|
)
|
|
|
$65.51
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
Unvested performance shares, end of period
|
|
182,209
|
|
|
|
$27.01
|
|
|
|
(1)
|
The number of performance shares that vest may vary from the number of target performance shares granted depending on the Company
’
s final TSR ranking for the approximate
three
-year performance period.
|
During the
nine months ended September 30,
2018
, the Company granted
93,771
target performance shares to certain employees and independent contractors, all of which occurred in the first quarter of 2018 as part of the Company’s annual grant of long-term equity incentive awards. Each performance share represents the right to receive
one
share of common stock, however, the number of performance shares that vest 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.
During the first quarter of 2018, as a result of the Company’s final TSR ranking during the performance period, a multiplier of
88%
was applied to the
56,517
target performance shares that were granted in 2015, resulting in the vesting of
49,458
shares and
7,059
shares that did not vest.
The grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was
$1.8 million
. 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,
2018
:
|
|
|
|
|
|
|
Grant Date Fair Value Assumptions
|
Number of simulations
|
|
500,000
|
Expected term (in years)
|
|
3.0
|
|
Expected volatility
|
|
61.5
|
%
|
Risk-free interest rate
|
|
2.4
|
%
|
Dividend yield
|
|
—
|
%
|
As of
September 30, 2018
, unrecognized compensation costs related to unvested performance shares were
$2.5 million
and will be recognized over a weighted average period of
2.0
years.
Stock-Based Compensation Expense, Net
Stock-based compensation expense associated with restricted stock awards and units, Cash SARs and performance shares, net of amounts capitalized, is included in “General and administrative, net” in the consolidated statements of income.
The Company recognized the following stock-based compensation expense, net for the
three and nine months ended September 30,
2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Restricted stock awards and units
|
|
|
$4,487
|
|
|
|
$5,311
|
|
|
|
$14,291
|
|
|
|
$16,184
|
|
Cash SARs
|
|
(868
|
)
|
|
429
|
|
|
3,505
|
|
|
(7,040
|
)
|
Performance shares
|
|
411
|
|
|
581
|
|
|
1,374
|
|
|
1,861
|
|
|
|
4,030
|
|
|
6,321
|
|
|
19,170
|
|
|
11,005
|
|
Less: amounts capitalized to oil and gas properties
|
|
(968
|
)
|
|
(1,455
|
)
|
|
(5,384
|
)
|
|
(2,543
|
)
|
Total stock-based compensation expense, net
|
|
|
$3,062
|
|
|
|
$4,866
|
|
|
|
$13,786
|
|
|
|
$8,462
|
|
10.
Derivative Instruments
Commodity Derivative Instruments
The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s most significant commodity price risk. While the use of commodity derivative instruments limits or partially reduces the downside risk of adverse commodity price movements, such use also limits the upside from favorable commodity price movements. The Company does not enter into commodity derivative instruments for speculative purposes.
The Company’s commodity derivative instruments, which settle on a monthly basis over the term of the contract for contracted volumes, consist of over-the-counter price swaps, three-way collars, sold call options and basis swaps, each of which is described below.
Price swaps
are settled based on differences between a fixed price and the settlement price of a referenced index. If the settlement price of the referenced index is below the fixed price, the Company receives the difference from the counterparty. If the referenced settlement price is above the fixed price, the Company pays the difference to the counterparty.
Three-way collars
consist of a purchased put option (floor price), a sold call option (ceiling price) and a sold put option (sub-floor price) and are settled based on differences between the floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and sub-floor price. If the settlement price of the referenced index is below the sub-floor price, the Company receives the difference between the floor price and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price and sub-floor price, the Company receives the difference between the floor price and the settlement price of the referenced index from the counterparty. If the settlement price of the referenced index is between the floor price and ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty.
Sold call options
are settled based on differences between the ceiling price and the settlement price of a referenced index. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty. If the settlement price of the referenced index is below the ceiling price, no payments are due to or from either party. Premiums from the sale of call options have been used to enhance the fixed price of certain contemporaneously executed price swaps. Purchased call options executed contemporaneously with sold call options in order to increase the ceiling price of existing sold call options have been presented on a net basis in the table below.
Basis swaps
are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. If the differential between the settlement prices of the two referenced indexes is greater than the fixed price differential, the Company receives the difference from the counterparty. If the differential between the settlement prices of the two referenced indexes is less than the fixed price differential, the Company pays the difference to the counterparty.
The referenced index of the Company’s price swaps, three-way collars and sold call options is U.S. New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) for crude oil, NYMEX Henry Hub for natural gas and OPIS Mont Belvieu Non-TET (“OPIS”) for NGL products, as applicable. The prices received by the Company for the sale of its production generally vary from these referenced index prices due to adjustments for delivery location (basis) and other factors. The referenced indexes of the Company’s basis swaps, which are used to mitigate location price risk for a portion of its production, are Argus WTI Cushing (“WTI Cushing”) and the applicable index price of the Company’s crude oil sales contracts is Argus WTI Midland (“WTI Midland”) for its Delaware Basin crude oil production and Argus Light Louisiana Sweet (“LLS”) for its Eagle Ford crude oil production.
The Company has incurred premiums on certain of its commodity derivative instruments in order to obtain a higher fixed price, higher floor price and/or higher ceiling price. Payment of these premiums are deferred until the applicable contracts settle on a monthly basis over the term of the contract or, in some cases, during the final 12 months of the contract and are referred to as deferred premium obligations.
As of
September 30, 2018
, the Company had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Period
|
|
Type of Contract
|
|
Index
|
|
Volumes
(Bbls
per day)
|
|
Fixed Price
($ per
Bbl)
|
|
Sub-Floor Price
($ per
Bbl)
|
|
Floor Price
($ per
Bbl)
|
|
Ceiling Price
($ per
Bbl)
|
|
Fixed
Price
Differential
($ per
Bbl)
|
Crude oil
|
|
4Q18
|
|
Price Swaps
|
|
NYMEX WTI
|
|
6,000
|
|
|
|
$49.55
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Crude oil
|
|
4Q18
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
24,000
|
|
|
—
|
|
|
|
$39.38
|
|
|
|
$49.06
|
|
|
|
$60.14
|
|
|
—
|
|
Crude oil
|
|
4Q18
|
|
Basis Swaps
|
|
LLS-WTI Cushing
|
|
18,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$5.11
|
|
Crude oil
|
|
4Q18
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($0.10
|
)
|
Crude oil
|
|
4Q18
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
3,388
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$71.33
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
2019
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
21,000
|
|
|
—
|
|
|
|
$40.71
|
|
|
|
$49.80
|
|
|
|
$67.80
|
|
|
—
|
|
Crude oil
|
|
2019
|
|
Basis Swaps
|
|
LLS-WTI Cushing
|
|
3,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$4.57
|
|
Crude oil
|
|
2019
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
7,389
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($4.82
|
)
|
Crude oil
|
|
2019
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$73.66
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
2020
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
13,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($1.27
|
)
|
Crude oil
|
|
2020
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
4,575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$75.98
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
2021
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Period
|
|
Type of Contract
|
|
Index
|
|
Volumes
(Bbls
per day)
|
|
Fixed Price
($ per
Bbl)
|
|
Sub-Floor Price
($ per
Bbl)
|
|
Floor Price
($ per
Bbl)
|
|
Ceiling Price
($ per
Bbl)
|
|
Fixed
Price
Differential
($ per
Bbl)
|
NGLs
|
|
4Q18
|
|
Price Swaps
|
|
OPIS-Ethane
|
|
2,200
|
|
|
|
$12.01
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
NGLs
|
|
4Q18
|
|
Price Swaps
|
|
OPIS-Propane
|
|
1,500
|
|
|
|
$34.23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
NGLs
|
|
4Q18
|
|
Price Swaps
|
|
OPIS-Butane
|
|
200
|
|
|
|
$38.85
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
NGLs
|
|
4Q18
|
|
Price Swaps
|
|
OPIS-Isobutane
|
|
600
|
|
|
|
$38.98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
NGLs
|
|
4Q18
|
|
Price Swaps
|
|
OPIS-Natural Gasoline
|
|
600
|
|
|
|
$55.23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Period
|
|
Type of Contract
|
|
Index
|
|
Volumes
(MMBtu
per day)
|
|
Fixed
Price
($ per
MMBtu)
|
|
Sub-Floor Price
($ per
MMBtu)
|
|
Floor Price
($ per
MMBtu)
|
|
Ceiling Price
($ per
MMBtu)
|
|
Fixed
Price
Differential
($ per
MMBtu)
|
Natural gas
|
|
4Q18
|
|
Price Swaps
|
|
NYMEX Henry Hub
|
|
25,000
|
|
|
|
$3.01
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural gas
|
|
4Q18
|
|
Sold Call Options
|
|
NYMEX Henry Hub
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
2019
|
|
Sold Call Options
|
|
NYMEX Henry Hub
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
2020
|
|
Sold Call Options
|
|
NYMEX Henry Hub
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$3.50
|
|
|
—
|
|
The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods often resulting in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), 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 commodity derivative instruments who are also lenders under the Company’s credit agreement (“Lender Counterparty”) allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the Lender Counterparty with the collateral securing the credit
agreement, thus eliminating the need for independent collateral posting. Counterparties to the Company’s commodity derivative instruments who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”) can require commodity derivative instruments to be novated to a Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with the Non-Lender Counterparty and therefore do not require the posting of cash collateral.
Because each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, 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 commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties to minimize its credit exposure to any individual counterparty.
Contingent Consideration Arrangements
The purchase and sale agreements of the ExL Acquisition and divestitures of the Company’s assets in the Niobrara, Marcellus and Utica, included contingent consideration arrangements that entitle the Company to receive or require the Company to pay specified amounts if commodity prices exceed specified thresholds, which are summarized in the table below. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for details of these acquisitions and divestitures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contingent Consideration Arrangements
|
|
Years
|
|
Threshold
(1)
|
|
Contingent Receipt (Payment) - Annual
|
|
Contingent Receipt (Payment) - Aggregate Limit
|
|
|
|
|
|
|
(In thousands)
|
Contingent ExL Consideration
|
|
2018
|
|
|
$50.00
|
|
|
|
($50,000
|
)
|
|
|
|
|
2019
|
|
50.00
|
|
|
(50,000
|
)
|
|
|
|
|
2020
|
|
50.00
|
|
|
(50,000
|
)
|
|
|
|
|
2021
|
|
50.00
|
|
|
(50,000
|
)
|
|
|
($125,000
|
)
|
|
|
|
|
|
|
|
|
|
Contingent Niobrara Consideration
|
|
2018
|
|
|
$55.00
|
|
|
|
$5,000
|
|
|
|
|
|
2019
|
|
55.00
|
|
|
5,000
|
|
|
|
|
|
2020
|
|
60.00
|
|
|
5,000
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Contingent Marcellus Consideration
|
|
2018
|
|
|
$3.13
|
|
|
|
$3,000
|
|
|
|
|
|
2019
|
|
3.18
|
|
|
3,000
|
|
|
|
|
|
2020
|
|
3.30
|
|
|
3,000
|
|
|
|
$7,500
|
|
|
|
|
|
|
|
|
|
|
Contingent Utica Consideration
|
|
2018
|
|
|
$50.00
|
|
|
|
$5,000
|
|
|
|
|
|
2019
|
|
53.00
|
|
|
5,000
|
|
|
|
|
|
2020
|
|
56.00
|
|
|
5,000
|
|
|
—
|
|
|
|
(1)
|
The price used to determine whether the specified threshold for each year has been met for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration. The price used to determine whether the specified threshold for each year has been met for the Marcellus Contingent Consideration is the average monthly settlement price per 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.
|
Derivative Assets and Liabilities
Commodity derivative instruments and contingent consideration arrangements are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. As of September 30, 2018, the Company had
$9.8 million
classified as current derivative assets and
$49.2 million
classified as current derivative liabilities, representing the first cash receipts and payments, expected to occur in January 2019, from settlement of contingent consideration assets and liabilities. 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 asset or liability fair values pursuant to the netting provisions of the ISDAs described above.
The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of
September 30, 2018
and
December 31, 2017
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
(In thousands)
|
Commodity derivative instruments
|
|
|
$19,408
|
|
|
|
($18,985
|
)
|
|
|
$423
|
|
Contingent Niobrara Consideration
|
|
4,920
|
|
|
—
|
|
|
4,920
|
|
Contingent Utica Consideration
|
|
4,915
|
|
|
—
|
|
|
4,915
|
|
Derivative assets
|
|
|
$29,243
|
|
|
|
($18,985
|
)
|
|
|
$10,258
|
|
Commodity derivative instruments
|
|
12,028
|
|
|
(12,028
|
)
|
|
—
|
|
Contingent Niobrara Consideration
|
|
6,755
|
|
|
—
|
|
|
6,755
|
|
Contingent Marcellus Consideration
|
|
1,315
|
|
|
—
|
|
|
1,315
|
|
Contingent Utica Consideration
|
|
7,300
|
|
|
—
|
|
|
7,300
|
|
Other assets
|
|
|
$27,398
|
|
|
|
($12,028
|
)
|
|
|
$15,370
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($123,611
|
)
|
|
|
$9,876
|
|
|
|
($113,735
|
)
|
Deferred premium obligations
|
|
(9,109
|
)
|
|
9,109
|
|
|
—
|
|
Contingent ExL Consideration
|
|
(49,160
|
)
|
|
—
|
|
|
(49,160
|
)
|
Derivative liabilities-current
|
|
|
($181,880
|
)
|
|
|
$18,985
|
|
|
|
($162,895
|
)
|
Commodity derivative instruments
|
|
(45,532
|
)
|
|
6,314
|
|
|
(39,218
|
)
|
Deferred premium obligations
|
|
(5,714
|
)
|
|
5,714
|
|
|
—
|
|
Contingent ExL Consideration
|
|
(62,885
|
)
|
|
—
|
|
|
(62,885
|
)
|
Derivative liabilities-non current
|
|
|
($114,131
|
)
|
|
|
$12,028
|
|
|
|
($102,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 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
|
|
|
$4,869
|
|
|
|
($4,869
|
)
|
|
|
$—
|
|
Derivative assets
|
|
|
$4,869
|
|
|
|
($4,869
|
)
|
|
|
$—
|
|
Commodity derivative instruments
|
|
9,505
|
|
|
(9,505
|
)
|
|
—
|
|
Contingent Marcellus Consideration
|
|
2,205
|
|
|
—
|
|
|
2,205
|
|
Contingent Utica Consideration
|
|
7,985
|
|
|
—
|
|
|
7,985
|
|
Other assets
|
|
|
$19,695
|
|
|
|
($9,505
|
)
|
|
|
$10,190
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($52,671
|
)
|
|
|
($4,450
|
)
|
|
|
($57,121
|
)
|
Deferred premium obligations
|
|
(9,319
|
)
|
|
9,319
|
|
|
—
|
|
Derivative liabilities-current
|
|
|
($61,990
|
)
|
|
|
$4,869
|
|
|
|
($57,121
|
)
|
Commodity derivative instruments
|
|
(24,609
|
)
|
|
(2,098
|
)
|
|
(26,707
|
)
|
Deferred premium obligations
|
|
(11,603
|
)
|
|
11,603
|
|
|
—
|
|
Contingent ExL Consideration
|
|
(85,625
|
)
|
|
—
|
|
|
(85,625
|
)
|
Derivative liabilities-non current
|
|
|
($121,837
|
)
|
|
|
$9,505
|
|
|
|
($112,332
|
)
|
See “Note
11.
Fair Value Measurements” for additional information 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, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the changes occur. Deferred premium obligations associated with the Company’s commodity
derivative instruments are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the deferred premium obligations are incurred. The net (gain) loss on derivatives in the consolidated statements of income for the
three and nine months ended September 30,
2018
and
2017
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
(Gain) Loss on Derivatives, Net
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$43,664
|
|
|
|
$8,409
|
|
|
|
$126,612
|
|
|
|
($39,754
|
)
|
NGL
|
|
5,086
|
|
|
—
|
|
|
9,885
|
|
|
—
|
|
Natural gas
|
|
(192
|
)
|
|
(2,183
|
)
|
|
(3,084
|
)
|
|
(12,902
|
)
|
Deferred premium obligations
|
|
—
|
|
|
10,151
|
|
|
—
|
|
|
17,652
|
|
Contingent ExL Consideration
|
|
9,990
|
|
|
8,000
|
|
|
26,420
|
|
|
8,000
|
|
Contingent Niobrara Consideration
|
|
(1,705
|
)
|
|
—
|
|
|
(3,795
|
)
|
|
—
|
|
Contingent Marcellus Consideration
|
|
215
|
|
|
—
|
|
|
890
|
|
|
—
|
|
Contingent Utica Consideration
|
|
(1,670
|
)
|
|
—
|
|
|
(4,230
|
)
|
|
—
|
|
(Gain) Loss on Derivatives, Net
|
|
|
$55,388
|
|
|
|
$24,377
|
|
|
|
$152,698
|
|
|
|
($27,004
|
)
|
Cash Received (Paid) for Derivative Settlements, Net
Cash flows are impacted to the extent that settlements of commodity derivative instruments, including deferred premium obligations, and contingent consideration arrangements result in cash received or paid during the period and are recognized as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash received or paid in settlement of contingent consideration assets or liabilities, respectively, are classified as cash flows from financing activities up to the divestiture or acquisition date fair value with any excess classified as cash flows from operating activities. For the
three and nine months ended September 30,
2018
and
2017
, there were no settlements of contingent consideration arrangements. The net cash received (paid) for derivative settlements in the consolidated statements of cash flows for the
three and nine months ended September 30,
2018
and
2017
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Cash Flows from Operating Activities
|
|
(In thousands)
|
Cash Received (Paid) for Derivative Settlements, Net
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
($21,261
|
)
|
|
|
$6,500
|
|
|
|
($54,594
|
)
|
|
|
$9,941
|
|
NGL
|
|
(2,641
|
)
|
|
—
|
|
|
(3,829
|
)
|
|
—
|
|
Natural gas
|
|
245
|
|
|
522
|
|
|
785
|
|
|
(731
|
)
|
Deferred premium obligations
|
|
(2,605
|
)
|
|
(566
|
)
|
|
(7,072
|
)
|
|
(1,496
|
)
|
Cash Received (Paid) for Derivative Settlements, Net
|
|
|
($26,262
|
)
|
|
|
$6,456
|
|
|
|
($64,710
|
)
|
|
|
$7,714
|
|
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 derivative instrument assets and liabilities measured at fair value on a recurring basis as of
September 30, 2018
and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
$423
|
|
|
|
$—
|
|
Contingent Niobrara Consideration
|
|
—
|
|
|
—
|
|
|
11,675
|
|
Contingent Marcellus Consideration
|
|
—
|
|
|
—
|
|
|
1,315
|
|
Contingent Utica Consideration
|
|
—
|
|
|
—
|
|
|
12,215
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
($152,953
|
)
|
|
|
$—
|
|
Contingent ExL Consideration
|
|
—
|
|
|
—
|
|
|
(112,045
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
Contingent Niobrara Consideration
|
|
—
|
|
|
—
|
|
|
—
|
|
Contingent Marcellus Consideration
|
|
—
|
|
|
—
|
|
|
2,205
|
|
Contingent Utica Consideration
|
|
—
|
|
|
—
|
|
|
7,985
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
($83,828
|
)
|
|
|
$—
|
|
Contingent ExL Consideration
|
|
—
|
|
|
—
|
|
|
(85,625
|
)
|
The 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 fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses 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, and are therefore designated as Level 2 within the valuation hierarchy. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for commodity derivative assets and the Company’s credit quality for commodity derivative liabilities.
The Company had
no
transfers into Level 1 and
no
transfers into or out of Level 2 for the
nine months ended September 30,
2018
and
2017
.
Contingent consideration arrangements.
The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors, and risk adjusted discount rates, which include adjustments for the counterparties’ credit quality for contingent consideration assets and the Company’s credit quality for the contingent consideration liabilities. As some of these assumptions are not observable throughout the full term of the contingent consideration arrangements, the contingent consideration arrangements were designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.
The following table presents the reconciliation of changes in the fair values of the contingent consideration arrangements, which were designated as Level 3 within the valuation hierarchy, for the
nine months ended September 30,
2018
and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
Contingent Consideration Arrangements
|
|
|
Assets
|
|
Liability
|
|
|
(In thousands)
|
December 31, 2017
|
|
|
$10,190
|
|
|
|
($85,625
|
)
|
Recognition of divestiture date fair value
|
|
7,880
|
|
|
—
|
|
Gain (loss) on changes in fair value, net
(1)
|
|
7,135
|
|
|
(26,420
|
)
|
Transfers into (out of) Level 3
|
|
—
|
|
|
—
|
|
September 30, 2018
|
|
|
$25,205
|
|
|
|
($112,045
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Contingent Consideration Arrangements
|
|
|
Assets
|
|
Liability
|
|
|
(In thousands)
|
December 31, 2016
|
|
|
$—
|
|
|
|
$—
|
|
Recognition of acquisition date fair value
|
|
—
|
|
|
(52,300
|
)
|
Loss on change in fair value
(1)
|
|
—
|
|
|
(8,000
|
)
|
Transfers into (out of) Level 3
|
|
—
|
|
|
—
|
|
September 30, 2017
|
|
|
$—
|
|
|
|
($60,300
|
)
|
|
|
(1)
|
Recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income.
|
See “Note
10.
Derivative Instruments” for additional information regarding the contingent consideration arrangements.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. 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 assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of 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 are therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include forward oil and gas price curves, 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. See “Note
3.
Acquisitions and Divestitures of Oil and Gas Properties” for details of assets acquired and liabilities assumed as of the acquisition date for the ExL Acquisition.
Fair Value of Other Financial Instruments
The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The 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 quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
|
(In thousands)
|
7.50% Senior Notes due 2020
|
|
|
$129,144
|
|
|
|
$130,000
|
|
|
|
$446,087
|
|
|
|
$459,518
|
|
6.25% Senior Notes due 2023
|
|
642,781
|
|
|
664,625
|
|
|
641,792
|
|
|
674,375
|
|
8.25% Senior Notes due 2025
|
|
245,927
|
|
|
268,750
|
|
|
245,605
|
|
|
274,375
|
|
Other long-term debt due 2028
|
|
—
|
|
|
—
|
|
|
4,425
|
|
|
4,445
|
|
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, 2018
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
$3,114,698
|
|
|
|
$133,308
|
|
|
|
$—
|
|
|
|
($3,096,917
|
)
|
|
|
$151,089
|
|
Total property and equipment, net
|
|
6,570
|
|
|
2,709,162
|
|
|
3,028
|
|
|
(3,833
|
)
|
|
2,714,927
|
|
Investment in subsidiaries
|
|
(576,826
|
)
|
|
—
|
|
|
—
|
|
|
576,826
|
|
|
—
|
|
Other assets
|
|
29,611
|
|
|
15,371
|
|
|
—
|
|
|
—
|
|
|
44,982
|
|
Total Assets
|
|
|
$2,574,053
|
|
|
|
$2,857,841
|
|
|
|
$3,028
|
|
|
|
($2,523,924
|
)
|
|
|
$2,910,998
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
$305,096
|
|
|
|
$3,347,575
|
|
|
|
$3,028
|
|
|
|
($3,099,937
|
)
|
|
|
$555,762
|
|
Long-term liabilities
|
|
1,357,294
|
|
|
87,092
|
|
|
—
|
|
|
15,879
|
|
|
1,460,265
|
|
Preferred stock
|
|
173,629
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
173,629
|
|
Total shareholders’ equity
|
|
738,034
|
|
|
(576,826
|
)
|
|
—
|
|
|
560,134
|
|
|
721,342
|
|
Total Liabilities and Shareholders’ Equity
|
|
|
$2,574,053
|
|
|
|
$2,857,841
|
|
|
|
$3,028
|
|
|
|
($2,523,924
|
)
|
|
|
$2,910,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
$3,441,633
|
|
|
|
$105,533
|
|
|
|
$—
|
|
|
|
($3,424,288
|
)
|
|
|
$122,878
|
|
Total property and equipment, net
|
|
5,953
|
|
|
2,630,707
|
|
|
3,028
|
|
|
(3,878
|
)
|
|
2,635,810
|
|
Investment in subsidiaries
|
|
(999,793
|
)
|
|
—
|
|
|
—
|
|
|
999,793
|
|
|
—
|
|
Other assets
|
|
9,270
|
|
|
10,346
|
|
|
—
|
|
|
—
|
|
|
19,616
|
|
Total Assets
|
|
|
$2,457,063
|
|
|
|
$2,746,586
|
|
|
|
$3,028
|
|
|
|
($2,428,373
|
)
|
|
|
$2,778,304
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
$165,701
|
|
|
|
$3,631,401
|
|
|
|
$3,028
|
|
|
|
($3,427,308
|
)
|
|
|
$372,822
|
|
Long-term liabilities
|
|
1,689,466
|
|
|
114,978
|
|
|
—
|
|
|
15,879
|
|
|
1,820,323
|
|
Preferred stock
|
|
214,262
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
214,262
|
|
Total shareholders’ equity
|
|
387,634
|
|
|
(999,793
|
)
|
|
—
|
|
|
983,056
|
|
|
370,897
|
|
Total Liabilities and Shareholders’ Equity
|
|
|
$2,457,063
|
|
|
|
$2,746,586
|
|
|
|
$3,028
|
|
|
|
($2,428,373
|
)
|
|
|
$2,778,304
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Total revenues
|
|
|
$38
|
|
|
|
$303,337
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$303,375
|
|
Total costs and expenses
|
|
85,242
|
|
|
135,920
|
|
|
—
|
|
|
(13
|
)
|
|
221,149
|
|
Income (loss) before income taxes
|
|
(85,204
|
)
|
|
167,417
|
|
|
—
|
|
|
13
|
|
|
82,226
|
|
Income tax expense
|
|
—
|
|
|
(880
|
)
|
|
—
|
|
|
—
|
|
|
(880
|
)
|
Equity in income of subsidiaries
|
|
166,537
|
|
|
—
|
|
|
—
|
|
|
(166,537
|
)
|
|
—
|
|
Net income
|
|
|
$81,333
|
|
|
|
$166,537
|
|
|
|
$—
|
|
|
|
($166,524
|
)
|
|
|
$81,346
|
|
Dividends on preferred stock
|
|
(4,457
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,457
|
)
|
Accretion on preferred stock
|
|
(771
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(771
|
)
|
Loss on redemption of preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income attributable to common shareholders
|
|
|
$76,105
|
|
|
|
$166,537
|
|
|
|
$—
|
|
|
|
($166,524
|
)
|
|
|
$76,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
)
|
Accretion on preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Loss on redemption of preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income attributable to common shareholders
|
|
|
$5,603
|
|
|
|
$61,878
|
|
|
|
$—
|
|
|
|
($61,907
|
)
|
|
|
$5,574
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Total revenues
|
|
|
$77
|
|
|
|
$792,551
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$792,628
|
|
Total costs and expenses
|
|
278,942
|
|
|
367,902
|
|
|
—
|
|
|
(45
|
)
|
|
646,799
|
|
Income (loss) before income taxes
|
|
(278,865
|
)
|
|
424,649
|
|
|
—
|
|
|
45
|
|
|
145,829
|
|
Income tax expense
|
|
—
|
|
|
(1,682
|
)
|
|
—
|
|
|
—
|
|
|
(1,682
|
)
|
Equity in income of subsidiaries
|
|
422,967
|
|
|
—
|
|
|
—
|
|
|
(422,967
|
)
|
|
—
|
|
Net income
|
|
|
$144,102
|
|
|
|
$422,967
|
|
|
|
$—
|
|
|
|
($422,922
|
)
|
|
|
$144,147
|
|
Dividends on preferred stock
|
|
(13,794
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,794
|
)
|
Accretion on preferred stock
|
|
(2,264
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,264
|
)
|
Loss on redemption of preferred stock
|
|
(7,133
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,133
|
)
|
Net income attributable to common shareholders
|
|
|
$120,911
|
|
|
|
$422,967
|
|
|
|
$—
|
|
|
|
($422,922
|
)
|
|
|
$120,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
)
|
Accretion on preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Loss on redemption of preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income attributable to common shareholders
|
|
|
$101,971
|
|
|
|
$184,589
|
|
|
|
$—
|
|
|
|
($184,659
|
)
|
|
|
$101,901
|
|
CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Net cash provided by (used in) operating activities
|
|
|
($218,926
|
)
|
|
|
$684,218
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$465,292
|
|
Net cash provided by (used in) investing activities
|
|
375,265
|
|
|
(284,076
|
)
|
|
—
|
|
|
(400,142
|
)
|
|
(308,953
|
)
|
Net cash used in financing activities
|
|
(163,464
|
)
|
|
(400,142
|
)
|
|
—
|
|
|
400,142
|
|
|
(163,464
|
)
|
Net decrease in cash and cash equivalents
|
|
(7,125
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,125
|
)
|
Cash and cash equivalents, beginning of period
|
|
9,540
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,540
|
|
Cash and cash equivalents, end of period
|
|
|
$2,415
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$2,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
13.
Supplemental Cash Flow Information
Supplemental cash flow disclosures and non-cash investing activities are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Supplemental cash flow disclosures:
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
|
$44,644
|
|
|
|
$59,389
|
|
|
|
|
|
|
Non-cash investing activities:
|
|
|
|
|
Increase in capital expenditure payables and accruals
|
|
|
$61,893
|
|
|
|
$98,829
|
|
Fair value of contingent consideration (assets) liabilities on date of (divestiture) acquisition
|
|
(7,880
|
)
|
|
52,300
|
|
Stock-based compensation expense capitalized to oil and gas properties
|
|
5,384
|
|
|
2,543
|
|
Asset retirement obligations capitalized to oil and gas properties
|
|
1,127
|
|
|
2,761
|
|
14.
Subsequent Events
Commodity Derivative Instruments
In October 2018, the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Period
|
|
Type of Contract
|
|
Index
|
|
Volumes
(Bbls
per day)
|
|
Fixed Price
($ per
Bbl)
|
|
Sub-Floor
Price
($ per
Bbl)
|
|
Floor
Price
($ per Bbl)
|
|
Ceiling Price
($ per
Bbl)
|
|
Fixed
Price
Differential
($ per
Bbl)
|
Crude oil
|
|
2019
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
6,000
|
|
|
—
|
|
|
|
$45.00
|
|
|
|
$55.00
|
|
|
|
$93.01
|
|
|
—
|
|
Crude oil
|
|
2019
|
|
Basis Swaps
|
|
LLS-WTI Cushing
|
|
1,000
|
|
|
|
$5.78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Redemption of 7.50% Senior Notes Due 2020
On October 18, 2018, the Company delivered a notice of conditional redemption to the trustee for its
7.50%
Senior Notes to call for redemption on November 19, 2018, the remaining
$130.0 million
outstanding aggregate principal amount of
7.50%
Senior Notes at a redemption price of
100%
of par, plus accrued and unpaid interest. The Company’s redemption obligation was conditioned on and subject to there being made available to the Company under its revolving credit facility a commitment amount of at least
$1.1 billion
as of November 19, 2018, which was satisfied on October 29, 2018 in connection with the amendment to the credit agreement discussed below, therefore, the Company’s redemption obligation is no longer conditional. As a result of the redemption, the Company expects to record a loss on extinguishment of debt of approximately
$0.8 million
, which is solely attributable to the write-off of unamortized premium and debt issuance costs.
Upon redemption of the
7.50%
Senior Notes, the May 4, 2022 maturity date of the credit agreement will no longer be subject to a springing maturity date of June 15, 2020.
Thirteenth Amendment to the Credit Agreement
On October 29, 2018, the Company entered into the thirteenth amendment to its credit agreement governing its revolving credit facility to, among other things, (i) establish the borrowing base at
$1.3 billion
, with an elected commitment amount of
$1.1 billion
, until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from
1.50%
-
2.50%
to
1.25%
-
2.25%
and base rate loans from
0.50%
-
1.50%
to
0.25%
-
1.25%
, each depending on the level of facility usage and each subject to an increase of
0.25%
for any period during which the ratio of Total Debt to EBITDA exceeds
3.00
to 1.00, (iii) amend the definition of Capital Leases, and (iv) amend certain other definitions and provisions.