NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.
Nature of Operations
Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company” or “Carrizo”), 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.
Proposed Merger of the Company with Callon
On July 14, 2019, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Callon Petroleum Company, a Delaware corporation (“Callon”). Pursuant to the Merger Agreement, the Company will be merged with and into Callon, with Callon continuing as the surviving entity (the “Merger”). The Merger was structured as a direct merger with the closing expected to occur in the fourth quarter of 2019.
On and subject to the terms and conditions set forth in the Merger Agreement, upon closing of the Merger, each share of Carrizo’s common stock, par value
$0.01
per share, issued and outstanding immediately prior to the effective time of the Merger will automatically be converted into the right to receive
2.05
shares of Callon’s common stock, par value
$0.01
per share (the “Exchange Ratio”). Callon’s common stock is listed and traded on the New York Stock Exchange (the “NYSE”) under the ticker symbol CPE. Pursuant to the Merger Agreement, three members of the Company’s board of directors will become directors of Callon immediately after the effective time of the Merger.
Pursuant to the terms of the Merger Agreement, each issued and outstanding share of the Company’s
8.875%
redeemable preferred stock, par value
$0.01
per share (the “Preferred Stock”), will either be converted into the right to receive
one
share of
8.875%
redeemable preferred stock, par value
$0.01
per share, of Callon, which will have substantially the same terms as the Preferred Stock or will be redeemed for an amount in cash specified in the Merger Agreement (the “Preferred Redemption”). Callon is obligated to deposit the amount required to effect the Preferred Redemption (the “Preferred Deposit”) no later than the open of business on the date of the closing of the Merger, though the Company is permitted to fund such amount if Callon fails to do so.
In connection with the proposed Merger, restricted stock awards and units and performance shares that are outstanding immediately prior to closing will generally become vested and converted into shares of Callon common stock based on the Exchange Ratio. Stock appreciation rights that will be settled in cash (“Cash SARs”) that are outstanding immediately prior to the closing will be canceled and converted into a vested stock appreciation right covering shares of Callon common stock, with the calculation of such conversion described in the Merger Agreement.
The completion of the Merger is subject to certain customary mutual closing conditions, including (i) the receipt of the required approvals from the shareholders of the Company and Callon, (ii) either (a) the approval by the holders of Preferred Stock or (b) the Preferred Deposit having been deposited and the Preferred Redemption having occurred, (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), which was terminated effective August 6, 2019, and (iv) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986. The obligation of each party to complete the Merger is also conditioned upon the other party’s representations and warranties being true and correct, subject to certain materiality exceptions, and the other party having performed in all material respects its obligations under the Merger Agreement.
The Merger Agreement contains termination rights for each of the Company and Callon, including, among other things, (i) by either the Company or Callon if the other party’s board of directors changes its recommendation with respect to the transactions contemplated by the Merger Agreement or if the other party willfully breaches the covenant not to solicit alternative business combination proposals from third parties, (ii) by the Company, if its board of directors changes its recommendation with respect to the transactions contemplated by the Merger Agreement and substantially concurrently the Company enters into an acquisition agreement providing for a Company Superior Proposal, as defined in the Merger Agreement, (iii) by the Company or Callon, if the approvals of either their common shareholders shall not have been obtained, (iv) by the Company or Callon, if in certain circumstances, the other party breaches or fails to perform any of its representations, warranties or covenants in the Merger Agreement, and (v) by the Company or Callon, if the Merger shall not have been consummated by February 14, 2020, with a possible extension to April 14, 2020 in certain circumstances. Upon termination of the Merger Agreement under differing specified circumstances, (i) the Company would be required to pay Callon a termination fee of
$47.4 million
or to reimburse Callon up to
$7.5 million
in expenses or (ii) Callon would be required to pay the Company a termination fee of
$57.0 million
or to reimburse the Company up to
$7.5 million
in expenses.
The capitalized terms which are not defined in this description of the proposed Merger, shall have the meaning given to such terms in the Merger Agreement. Additional information on the proposed Merger is included in the Form 8-K filed with the SEC on July 15, 2019 and in this Quarterly Report on Form 10-Q, including “Part II. Other Information—Item 1A. Risk Factors”.
2.
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
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. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended
December 31, 2018
(“
2018
Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s
2018
Annual Report.
Recently Adopted Accounting Standards
Leases.
Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842) (“ASC 842”), using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 significantly changes accounting for leases by requiring that lessees recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions. However, ASC 842 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Upon adoption, the Company implemented policy elections and practical expedients which include the following:
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•
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package of practical expedients which allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance;
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•
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excluding ROU assets and lease liabilities for leases with terms that are less than one year;
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•
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combining lease and non-lease components and accounting for them as a single lease (elected by asset class);
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•
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excluding land easements that existed or expired prior to adoption; and
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•
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policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.
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As a result of adopting ASC 842, the Company recorded lease liabilities of approximately
$75.2 million
and associated ROU assets of approximately
$69.1 million
on its consolidated balance sheets. The difference between the lease liabilities and ROU assets is due to a rent holiday and lease build-out incentives that were recorded as deferred lease liabilities under legacy lease accounting guidance. The adoption of ASC 842 did not materially change the Company’s consolidated statements of income or consolidated statements of cash flows. See “Note
6.
Leases” for further discussion.
Subsequent Events
The Company evaluates subsequent events through the date the financial statements are issued. See “Note
16.
Subsequent Events” for further discussion.
3.
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
June 30, 2019
and
December 31, 2018
, receivables from contracts with customers were
$76.9 million
and
$77.1 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 operations.
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.
4.
Acquisitions and Divestitures of Oil and Gas Properties
2019 Acquisitions and Divestitures
The Company did not have any material acquisitions or divestitures for the
three and six months ended June 30,
2019
. See “Note
1.
Nature of Operations” for details of the proposed Merger which was announced on July 15, 2019.
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, paid
$183.4 million
upon initial closing on October 17, 2018, and received
$8.3 million
as a post-closing adjustment on March 28, 2019, for an aggregate purchase price of
$196.6 million
.
The Devon 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 future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
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Preliminary Purchase Price Allocation
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(In thousands)
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Assets
|
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Other current assets
|
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$216
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Oil and gas properties
|
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Proved properties
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47,118
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Unproved properties
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150,253
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Total oil and gas properties
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$197,371
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Total assets acquired
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$197,587
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Liabilities
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Revenues and royalties payable
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$786
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Asset retirement obligations
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170
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Total liabilities assumed
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$956
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Net Assets Acquired
|
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$196,631
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The results of operations for the Devon Acquisition have been included in the Company’s consolidated statements of income since the October 17, 2018 closing date, including total revenues and net income attributable to common shareholders for the
three and six months ended June 30,
2019
as shown in the table below:
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Three Months Ended
June 30, 2019
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Six Months Ended
June 30, 2019
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(In thousands)
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Total revenues
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$4,342
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|
$8,718
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Net Income Attributable to Common Shareholders
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$2,020
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$4,716
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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
as a post-closing adjustment 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
as a post-closing adjustment 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. See “Note
13.
Derivative Instruments” and “Note
14.
Fair Value Measurements” for further discussion.
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.
5.
Property and Equipment, Net
As of
June 30, 2019
and
December 31, 2018
, total property and equipment, net consisted of the following:
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June 30,
2019
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December 31,
2018
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(In thousands)
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Oil and gas properties, full cost method
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Proved properties
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$6,685,543
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$6,278,321
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Accumulated depreciation, depletion and amortization and impairments
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(4,098,202
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)
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(3,944,851
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)
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Proved properties, net
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2,587,341
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2,333,470
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Unproved properties, not being amortized
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Unevaluated leasehold and seismic costs
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580,369
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608,830
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Capitalized interest
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76,607
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65,003
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Total unproved properties, not being amortized
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656,976
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673,833
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Other property and equipment
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30,580
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29,191
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Accumulated depreciation
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(19,392
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)
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(17,970
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)
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Other property and equipment, net
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11,188
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11,221
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Total property and equipment, net
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$3,255,505
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$3,018,524
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Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was
$13.28
and
$13.74
for the
three months ended June 30,
2019
and
2018
, respectively, and
$13.28
and
$13.73
for the
six months ended June 30,
2019
and
2018
, respectively.
The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration, and development activities totaling
$3.8 million
and
$6.1 million
for the
three months ended June 30,
2019
and
2018
, respectively, and
$12.9 million
and
$12.7 million
for the
six months ended June 30,
2019
and
2018
, 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
$8.6 million
and
$8.7 million
for the
three months ended June 30,
2019
and
2018
, respectively, and
$17.6 million
and
$19.1 million
for the
six months ended June 30,
2019
and
2018
, respectively.
6.
Leases
The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.
Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.
Types of Leases
The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.
Drilling Rigs.
The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for
one
to
three
years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.
Office Space
. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between
one
to
fifteen
years. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative, net” in its consolidated statements of income.
Well Equipment.
The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than
one
year to
three
years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating expense” in the Company’s statements of income.
The tables below, which present the components of lease costs, supplemental balance sheet information, and supplemental cash flow information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.
The table below presents the components of the Company’s lease costs for the
three and six months ended June 30,
2019
.
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Three Months Ended June 30, 2019
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Six Months Ended June 30, 2019
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(In thousands)
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Components of Lease Costs
|
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Finance lease costs
|
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Amortization of right-of-use assets
(1)
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$410
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$784
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Interest on lease liabilities
(2)
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131
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276
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Operating lease costs
(3)
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8,700
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|
22,780
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Short-term lease costs
(4)
|
|
245
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|
463
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Variable lease costs
(5)
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|
50
|
|
|
152
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Total lease costs
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$9,536
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|
$24,455
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(1)
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Included as a component of “Depletion, depreciation and amortization” in the consolidated statements of income.
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(2)
|
Included as a component of “Interest expense, net” in the consolidated statements of income.
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(3)
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For the three and six months ended June 30, 2019, approximately
$6.1 million
and
$17.6 million
are costs associated with drilling rigs and are capitalized to “Oil and gas properties” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative, net” and “Lease operating expense” in the consolidated statements of income.
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(4)
|
Short-term lease costs are primarily associated with certain well equipment that have lease terms for less than one year and are components of “Lease operating expense” in the consolidated statements of income.
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(5)
|
Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
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The table below presents supplemental balance sheet information for the Company’s leases as of
June 30, 2019
.
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|
June 30, 2019
|
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|
(In thousands)
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Leases
|
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Operating leases:
|
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Operating lease ROU assets
|
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$64,615
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Current operating lease liabilities
|
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|
$34,049
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Long-term operating lease liabilities
|
|
36,526
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Total operating lease liabilities
|
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|
$70,575
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Financing leases:
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Other property and equipment, at cost
|
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|
$7,810
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Accumulated depreciation
|
|
(5,170
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)
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Other property and equipment, net
|
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|
$2,640
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Current financing lease liabilities
(1)
|
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|
$1,918
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Long-term financing lease liabilities
(2)
|
|
1,034
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Total financing lease liabilities
|
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|
$2,952
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(1)
|
Included in “Other current liabilities” in the consolidated balance sheets.
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(2)
|
Included in “Other long-term liabilities” in the consolidated balance sheets.
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The table below presents supplemental cash flow information for the Company’s leases for the
six months ended June 30,
2019
.
|
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Six Months Ended June 30, 2019
|
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(In thousands)
|
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Supplemental Cash Flow Information
|
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Cash paid for amounts included in the measurement of lease liabilities:
|
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Operating cash flows from operating leases
|
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|
$5,338
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Investing cash flows from operating leases
|
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|
$22,896
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Operating cash flows from financing leases
|
|
|
$276
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|
Financing cash flows from financing leases
|
|
|
$879
|
|
|
|
|
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ROU assets obtained in exchange for lease liabilities
|
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Operating leases
|
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|
$9,404
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Financing leases
|
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|
$1,082
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The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of
June 30, 2019
.
|
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|
June 30, 2019
|
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Weighted Average Remaining Lease Term (In years)
|
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Operating leases
|
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5.1 years
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Financing leases
|
|
2.3 years
|
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Weighted Average Discount Rate
|
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Operating leases
|
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8.0
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%
|
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Financing leases
|
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12.9
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%
|
The table below presents the maturity of the Company’s lease liabilities as of
June 30, 2019
.
|
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|
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Operating Leases
|
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Financing Leases
|
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(In thousands)
|
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July - December 2019
|
|
|
$20,842
|
|
|
|
$1,113
|
|
|
2020
|
|
27,856
|
|
|
1,475
|
|
|
2021
|
|
7,726
|
|
|
275
|
|
|
2022
|
|
3,697
|
|
|
234
|
|
|
2023
|
|
3,680
|
|
|
232
|
|
|
2024 and Thereafter
|
|
21,608
|
|
|
39
|
|
|
Total lease payments
|
|
85,409
|
|
|
3,368
|
|
|
Less: Imputed interest
|
|
(14,834
|
)
|
|
(416
|
)
|
|
Total lease liabilities
|
|
|
$70,575
|
|
|
|
$2,952
|
|
7.
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) benefit differed from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of
21%
for the
three and six months ended June 30,
2019
and
2018
, to income before income taxes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
Income before income taxes
|
|
|
$109,784
|
|
|
|
$35,792
|
|
|
|
$81,752
|
|
|
|
$63,603
|
|
|
Income tax expense at the U.S. federal statutory rate
|
|
(23,055
|
)
|
|
(7,517
|
)
|
|
(17,168
|
)
|
|
(13,357
|
)
|
|
State income tax expense, net of U.S. federal income tax benefit
|
|
(874
|
)
|
|
(487
|
)
|
|
(626
|
)
|
|
(806
|
)
|
|
Tax deficiencies related to stock-based compensation
|
|
(176
|
)
|
|
(16
|
)
|
|
(2,114
|
)
|
|
(2,542
|
)
|
|
(Recapture) release of valuation allowance
|
|
(1,423
|
)
|
|
—
|
|
|
177,723
|
|
|
—
|
|
|
Decrease in valuation allowance due to current period activity
|
|
23,211
|
|
|
8,048
|
|
|
19,273
|
|
|
16,449
|
|
|
Other
|
|
18
|
|
|
(511
|
)
|
|
8
|
|
|
(546
|
)
|
|
Income tax (expense) benefit
|
|
|
($2,299
|
)
|
|
|
($483
|
)
|
|
|
$177,096
|
|
|
|
($802
|
)
|
Deferred Tax Asset Valuation Allowance
The deferred tax asset valuation allowance was
$45.9 million
and
$242.9 million
as of
June 30, 2019
and
December 31, 2018
, respectively. Throughout 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. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016. As of March 31, 2019 and June 30, 2019, the Company is in a cumulative three-year pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, the Company concluded that it is more likely than not that the deferred tax assets would be realized and released
$179.1 million
of the valuation allowance during the first quarter of 2019. During the second quarter of 2019, the Company reduced the prior valuation allowance release by
$1.4 million
as a result of updating the Company’s forecasted taxable income for 2019 bringing the cumulative release of the valuation allowance to
$177.7 million
. The reduction of the release of the valuation allowance in the second quarter of 2019 is recognized as a decrease in deferred tax assets and an increase in income tax expense, while the cumulative release of the valuation allowance for the six months ended June 30, 2019 is recognized as an increase in deferred tax assets and an income tax benefit.
8.
Long-Term Debt
Long-term debt consisted of the following as of
June 30, 2019
and
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2019
|
|
December 31,
2018
|
|
|
|
(In thousands)
|
|
Senior Secured Revolving Credit Facility due 2022
|
|
|
$841,328
|
|
|
|
$744,431
|
|
|
6.25% Senior Notes due 2023
|
|
650,000
|
|
|
650,000
|
|
|
Unamortized debt issuance costs for 6.25% Senior Notes
|
|
(6,180
|
)
|
|
(6,878
|
)
|
|
8.25% Senior Notes due 2025
|
|
250,000
|
|
|
250,000
|
|
|
Unamortized debt issuance costs for 8.25% Senior Notes
|
|
(3,730
|
)
|
|
(3,962
|
)
|
|
Long-term debt
|
|
|
$1,731,418
|
|
|
|
$1,633,591
|
|
Senior Secured Revolving Credit Facility
The Company has a senior secured revolving credit facility with a syndicate of banks that, as of
June 30, 2019
, had a borrowing base of
$1.35 billion
, with an elected commitment amount of
$1.25 billion
, and borrowings outstanding of
$841.3 million
at a weighted average interest rate of
4.14%
. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.
On March 27, 2019, the Company entered into the fourteenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at
$1.35 billion
, with an elected commitment amount of
$1.25 billion
, until the next redetermination thereof, (ii) amend the definition of Current Ratio, and (iii) amend certain other definitions and provisions.
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%
|
|
0.25%
|
|
1.25%
|
|
0.375%
|
|
Greater than or equal to 25% but less than 50%
|
|
0.50%
|
|
1.50%
|
|
0.375%
|
|
Greater than or equal to 50% but less than 75%
|
|
0.75%
|
|
1.75%
|
|
0.500%
|
|
Greater than or equal to 75% but less than 90%
|
|
1.00%
|
|
2.00%
|
|
0.500%
|
|
Greater than or equal to 90%
|
|
1.25%
|
|
2.25%
|
|
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 issuance costs and is net of cash and cash equivalents, EBITDA is 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 and excludes the Contingent ExL Consideration, which is described in “Note
13.
Derivative Instruments.” As of
June 30, 2019
, the ratio of Total Debt to EBITDA was
2.40
to 1.00 and the Current Ratio was
1.73
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.
Due to the proposed Merger, our regular redetermination scheduled for the fall of 2019 was postponed to occur on or about February 14, 2020.
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. The Company paid a total of
$336.9 million
upon the redemptions, 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
4.
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
.
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
.
Subsidiary Guarantors
The Company’s Senior Notes are guaranteed by its subsidiary guarantors, which are all
100%
owned by the parent company. The guarantees are full and unconditional and joint and several. Carrizo Oil & Gas, Inc., as the parent company, has no independent assets and operations. Any subsidiaries of the parent company, other than the subsidiary guarantors, are minor. In addition, there are no significant restrictions on the ability of the parent company or any guarantor to obtain funds from its subsidiaries by dividend or loan.
9.
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.
10.
Preferred Stock and Common Stock Warrants
See “Note
1.
Nature of Operations” for discussion of the impact to the Preferred Stock as a result of the proposed Merger.
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 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 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 Warrants are presented in “Additional paid-in capital” in the consolidated balance sheets at their issuance date fair value.
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 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 table below sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the
six months ended June 30,
2019
and
2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
Preferred Stock, beginning of period
|
|
|
$174,422
|
|
|
|
$214,262
|
|
|
Redemption of Preferred Stock
|
|
—
|
|
|
(42,897
|
)
|
|
Accretion on Preferred Stock
|
|
1,634
|
|
|
1,493
|
|
|
Preferred Stock, end of period
|
|
|
$176,056
|
|
|
|
$172,858
|
|
Loss on Redemption of 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.
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 accrued and unpaid dividends of
$0.5 million
. 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.
11.
Stock-Based Compensation
See “Note
1.
Nature of Operations” for discussion of the impact to the Company’s restricted stock awards and units, performance shares, and Cash SARs as a result of the proposed Merger.
At the Company’s annual meeting on May 16, 2019, the shareholders approved the proposal to amend and restate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “A&R 2017 Incentive Plan”),which included an increase to the number of shares available for issuance under the A&R 2017 Incentive Plan. As of
June 30, 2019
, there were
3,164,691
shares of common stock available for grant under the A&R 2017 Incentive Plan assuming all future grants will be full value stock awards. The Company has not granted stock appreciation rights to be settled in shares of common stock and has no outstanding stock options. See “Note 11. Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for details of the Company’s equity-based incentive plans.
Restricted Stock Awards and Units
The table below summarizes restricted stock award and unit activity for the three and
six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
|
Unvested, beginning of period
|
|
3,320,060
|
|
|
|
$14.16
|
|
|
2,263,830
|
|
|
|
$19.15
|
|
|
Granted
|
|
115,936
|
|
|
|
$11.90
|
|
|
1,250
|
|
|
|
$15.43
|
|
|
Vested
|
|
(52,639
|
)
|
|
|
$25.20
|
|
|
(43,992
|
)
|
|
|
$25.76
|
|
|
Forfeited
|
|
(47,464
|
)
|
|
|
$12.05
|
|
|
(9,915
|
)
|
|
|
$18.04
|
|
|
Unvested, end of period
|
|
3,335,893
|
|
|
|
$13.94
|
|
|
2,211,173
|
|
|
|
$19.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
|
Restricted Stock Awards and Units
|
|
Weighted Average Grant Date
Fair Value
|
|
Unvested, beginning of period
|
|
2,266,667
|
|
|
|
$19.28
|
|
|
1,482,655
|
|
|
|
$28.07
|
|
|
Granted
|
|
2,034,619
|
|
|
|
$11.06
|
|
|
1,348,415
|
|
|
|
$14.68
|
|
|
Vested
|
|
(904,973
|
)
|
|
|
$20.91
|
|
|
(608,904
|
)
|
|
|
$31.43
|
|
|
Forfeited
|
|
(60,420
|
)
|
|
|
$13.14
|
|
|
(10,993
|
)
|
|
|
$19.17
|
|
|
Unvested, end of period
|
|
3,335,893
|
|
|
|
$13.94
|
|
|
2,211,173
|
|
|
|
$19.02
|
|
Grant activity for the three months ended June 30, 2019 primarily consisted of restricted stock units to non-employee directors for their service for the 2019-2020 director term. These grants to the non-employee directors vest on the earlier of the date of the 2020 Annual Meeting of Shareholders and June 30, 2020. Grant activity for the six months ended June 30, 2019 primarily consisted of restricted stock units to employees as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. These restricted stock units vest ratably over an approximate
three
-year period.
As a result of the approval of the A&R 2017 Incentive Plan by shareholders, the Compensation Committee determined that the Company would settle the restricted stock units granted in the first quarter of 2019 in common stock rather than cash upon vesting. As such, the Company modified these restricted stock units, which were previously accounted for as liability awards to equity awards and reclassified the fair value of these awards to shareholders’ equity in the consolidated balance sheets.
The aggregate fair value of restricted stock awards and units that vested during the
three months ended June 30,
2019
and
2018
was
$0.7 million
and
$1.0 million
, respectively, and
$10.5 million
and
$9.9 million
for the
six months ended June 30,
2019
and
2018
, respectively. As of
June 30, 2019
and
2018
, unrecognized compensation costs related to unvested restricted stock awards and units were
$38.3 million
and
$30.5 million
, respectively, to be recognized over a weighted average period of
2.2
years.
Cash SARs
There was no activity for Cash SARs for the
three months ended June 30,
2019
and
2018
. The table below summarizes the activity for Cash SARs for the
six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
Cash SARs
|
|
Weighted
Average
Exercise
Prices
|
|
Weighted Average Remaining Life
(In years)
|
|
Cash SARs
|
|
Weighted
Average
Exercise
Prices
|
|
Weighted Average Remaining Life
(In years)
|
|
Outstanding, beginning of period
|
|
1,330,924
|
|
|
|
$21.35
|
|
|
|
|
714,238
|
|
|
|
$27.12
|
|
|
|
|
Granted
|
|
770,775
|
|
|
|
$10.98
|
|
|
|
|
616,686
|
|
|
|
$14.67
|
|
|
|
|
Exercised
|
|
—
|
|
|
|
$—
|
|
|
|
|
—
|
|
|
|
$—
|
|
|
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
|
|
|
—
|
|
|
|
$—
|
|
|
|
|
Expired
|
|
—
|
|
|
|
$—
|
|
|
|
|
—
|
|
|
|
$—
|
|
|
|
|
Outstanding, end of period
|
|
2,101,699
|
|
|
|
$17.55
|
|
|
4.9
|
|
1,330,924
|
|
|
|
$21.35
|
|
|
4.8
|
|
Vested, end of period
|
|
919,800
|
|
|
|
$24.34
|
|
|
|
|
543,018
|
|
|
|
$27.18
|
|
|
|
|
Vested and exercisable, end of period
|
|
—
|
|
|
|
$24.34
|
|
|
3.0
|
|
543,018
|
|
|
|
$27.18
|
|
|
3.0
|
Grant activity consisted of Cash SARs to certain employees as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. The Cash SARs granted in the first quarter of
2019
and
2018
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
$4.6 million
and
$4.9 million
for the
six months ended June 30,
2019
and
2018
. The following table summarizes the assumptions used and the resulting grant date fair value of the Cash SARs granted during the
six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
Expected term (in years)
|
|
6.1
|
|
|
6.0
|
|
|
Expected volatility
|
|
56.0
|
%
|
|
54.3
|
%
|
|
Risk-free interest rate
|
|
2.6
|
%
|
|
2.8
|
%
|
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
Grant date fair value per Cash SAR
|
|
$6.00
|
|
$7.89
|
The aggregate intrinsic value of Cash SARs outstanding as of
June 30, 2019
and
2018
was
zero
and
$9.1 million
, respectively, and the aggregate intrinsic value of Cash SARs vested and exercisable as of
June 30, 2019
and
2018
was
zero
and
$0.5 million
. As of
June 30, 2019
and
December 31, 2018
, the liabilities for Cash SARs were
$2.1 million
and
$1.8 million
, all of which was classified as “Other current liabilities,” in the respective consolidated balance sheets. As of
June 30, 2019
and
2018
, unrecognized compensation costs related to unvested Cash SARs were
$5.1 million
and
$11.3 million
, respectively, to be recognized over a weighted average period of
2.4
years and
2.6
years, respectively.
Performance Shares
There was no performance share activity for the
three months ended June 30,
2019
and
2018
. The table below summarizes performance share activity for the
six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
Target Performance Shares
(1)
|
|
Weighted Average Grant Date
Fair Value
|
|
Target Performance Shares
(1)
|
|
Weighted Average Grant Date
Fair Value
|
|
Unvested, beginning of period
|
|
182,209
|
|
|
|
$27.01
|
|
|
144,955
|
|
|
|
$47.14
|
|
|
Granted
|
|
130,302
|
|
|
|
$14.20
|
|
|
93,771
|
|
|
|
$19.09
|
|
|
Vested at end of performance period
|
|
(31,244
|
)
|
|
|
$35.71
|
|
|
(49,458
|
)
|
|
|
$65.51
|
|
|
Did not vest at end of performance period
|
|
(10,407
|
)
|
|
|
$35.71
|
|
|
(7,059
|
)
|
|
|
$65.51
|
|
|
Forfeited
|
|
—
|
|
|
|
$—
|
|
|
—
|
|
|
|
$—
|
|
|
Unvested, end of period
|
|
270,860
|
|
|
|
$19.51
|
|
|
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.
|
Grant activity consisted of performance shares as part of the annual grant of long-term equity incentive awards to certain employees that occurred in the first quarter of 2019 and 2018. 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.
The following table presents the results of the Company’s final TSR ranking during the performance periods that ended during the
six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
Target performance shares granted
|
|
41,651
|
|
56,517
|
|
Multiplier
|
|
75
|
%
|
|
88
|
%
|
|
Performance shares vested
|
|
31,244
|
|
49,458
|
|
Performance shares that did not vest
|
|
10,407
|
|
7,059
|
|
Aggregate fair value of performance shares vested (In millions)
|
|
$0.4
|
|
$0.8
|
For the
six months ended June 30,
2019
and
2018
, the grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was
$1.9 million
and
$1.8 million
, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance share for the grant activity during the
six months ended June 30,
2019
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
Number of simulations
|
|
500,000
|
|
500,000
|
|
Expected term (in years)
|
|
3.1
|
|
|
3.0
|
|
|
Expected volatility
|
|
58.2
|
%
|
|
61.5
|
%
|
|
Risk-free interest rate
|
|
2.5
|
%
|
|
2.4
|
%
|
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
Grant date fair value per performance share
|
|
$14.20
|
|
$19.09
|
As of
June 30, 2019
and
2018
, unrecognized compensation costs related to unvested performance shares were
$3.1 million
and
$2.9 million
, respectively, to be recognized over a weighted average period of
2.1
years and
2.2
years, respectively.
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 six months ended June 30,
2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
Restricted stock awards and units
|
|
|
$5,358
|
|
|
|
$4,720
|
|
|
|
$10,181
|
|
|
|
$9,804
|
|
|
Cash SARs
|
|
(426
|
)
|
|
5,788
|
|
|
334
|
|
|
4,373
|
|
|
Performance shares
|
|
436
|
|
|
406
|
|
|
871
|
|
|
963
|
|
|
|
|
5,368
|
|
|
10,914
|
|
|
11,386
|
|
|
15,140
|
|
|
Less: amounts capitalized to oil and gas properties
|
|
(1,514
|
)
|
|
(3,708
|
)
|
|
(3,417
|
)
|
|
(4,416
|
)
|
|
Total stock-based compensation expense, net
|
|
|
$3,854
|
|
|
|
$7,206
|
|
|
|
$7,969
|
|
|
|
$10,724
|
|
12.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands, except per share amounts)
|
|
Net Income
|
|
|
$107,485
|
|
|
|
$35,309
|
|
|
|
$258,848
|
|
|
|
$62,801
|
|
|
Dividends on preferred stock
|
|
(4,452
|
)
|
|
(4,474
|
)
|
|
(8,812
|
)
|
|
(9,337
|
)
|
|
Accretion on preferred stock
|
|
(833
|
)
|
|
(740
|
)
|
|
(1,634
|
)
|
|
(1,493
|
)
|
|
Loss on redemption of preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,133
|
)
|
|
Net Income Attributable to Common Shareholders
|
|
|
$102,200
|
|
|
|
$30,095
|
|
|
|
$248,402
|
|
|
|
$44,838
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average common shares outstanding
|
|
92,497
|
|
|
82,058
|
|
|
92,121
|
|
|
81,802
|
|
|
Dilutive effect of restricted stock and performance shares
|
|
203
|
|
|
967
|
|
|
358
|
|
|
798
|
|
|
Dilutive effect of common stock warrants
|
|
—
|
|
|
828
|
|
|
—
|
|
|
640
|
|
|
Diluted weighted average common shares outstanding
|
|
92,700
|
|
|
83,853
|
|
|
92,479
|
|
|
83,240
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Common Shareholders Per Common Share
|
|
|
|
|
|
|
|
Basic
|
|
|
$1.10
|
|
|
|
$0.37
|
|
|
|
$2.70
|
|
|
|
$0.55
|
|
|
Diluted
|
|
|
$1.10
|
|
|
|
$0.36
|
|
|
|
$2.69
|
|
|
|
$0.54
|
|
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 June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
Anti-dilutive restricted stock and performance shares
|
|
3,077
|
|
|
16
|
|
|
1,526
|
|
|
19
|
|
|
Anti-dilutive common stock warrants
|
|
2,750
|
|
|
—
|
|
|
2,750
|
|
|
—
|
|
|
Total weighted average anti-dilutive securities
|
|
5,827
|
|
|
16
|
|
|
4,276
|
|
|
19
|
|
13.
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 and NYMEX Henry Hub for natural gas, as applicable. The index price the Company receives on its crude oil basis swaps is Argus WTI Cushing (“WTI Cushing”) plus or minus a fixed price differential and the index price it pays is Argus WTI Midland (“WTI Midland”) or Argus Light Louisiana Sweet (“LLS”). The index price the Company receives on its natural gas basis swaps is NYMEX Henry Hub minus a fixed price differential and the index price it pays is Platt’s Inside FERC West Texas Waha (“Waha”).
The Company has incurred premiums on certain of its commodity derivative instruments in order to obtain a 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
June 30, 2019
, 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
|
|
3Q19
|
|
Price Swaps
|
|
NYMEX WTI
|
|
5,000
|
|
|
|
$64.80
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Crude oil
|
|
3Q19
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
27,000
|
|
|
—
|
|
|
|
$41.67
|
|
|
|
$50.96
|
|
|
|
$74.23
|
|
|
—
|
|
|
Crude oil
|
|
3Q19
|
|
Basis Swaps
|
|
LLS-WTI Cushing
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$5.16
|
|
|
Crude oil
|
|
3Q19
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
9,100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($4.44
|
)
|
|
Crude oil
|
|
3Q19
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
4Q19
|
|
Price Swaps
|
|
NYMEX WTI
|
|
5,000
|
|
|
|
$64.80
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Crude oil
|
|
4Q19
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
27,000
|
|
|
—
|
|
|
|
$41.67
|
|
|
|
$50.96
|
|
|
|
$74.23
|
|
|
—
|
|
|
Crude oil
|
|
4Q19
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
9,200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($4.64
|
)
|
|
Crude oil
|
|
4Q19
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
2020
|
|
Price Swaps
|
|
NYMEX WTI
|
|
3,000
|
|
|
|
$55.06
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Crude oil
|
|
2020
|
|
Three-Way Collars
|
|
NYMEX WTI
|
|
12,000
|
|
|
—
|
|
|
|
$45.63
|
|
|
|
$55.63
|
|
|
|
$66.04
|
|
|
—
|
|
|
Crude oil
|
|
2020
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
10,658
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($1.68
|
)
|
|
Crude oil
|
|
2020
|
|
Sold Call Options
|
|
NYMEX WTI
|
|
4,575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$75.98
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
2021
|
|
Basis Swaps
|
|
WTI Midland-WTI Cushing
|
|
8,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Period
|
|
Type of Contract
|
|
Index
|
|
Volumes
(MMBtu
per day)
|
|
Fixed Price
($ per
MMBtu)
|
|
Sub-Floor Price
($ per
MMBtu)
|
|
Floor Price
($ per
MMBtu)
|
|
Ceiling Price
($ per
MMBtu)
|
|
Fixed Price
Differential
($ per
MMBtu)
|
|
Natural gas
|
|
3Q19
|
|
Basis Swaps
|
|
Waha-NYMEX Henry Hub
|
|
42,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($1.49
|
)
|
|
Natural gas
|
|
3Q19
|
|
Sold Call Options
|
|
NYMEX Henry Hub
|
|
33,000
|
|
|
|
|
—
|
|
|
—
|
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
4Q19
|
|
Basis Swaps
|
|
Waha-NYMEX Henry Hub
|
|
42,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($1.30
|
)
|
|
Natural gas
|
|
4Q19
|
|
Sold Call Options
|
|
NYMEX Henry Hub
|
|
33,000
|
|
|
|
|
—
|
|
|
—
|
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
2020
|
|
Basis Swaps
|
|
Waha-NYMEX Henry Hub
|
|
29,541
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
($0.77
|
)
|
|
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. As of June 30, 2019, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty.
Contingent Consideration Arrangements
The purchase and sale agreements for the acquisition of properties in the Delaware Basin from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (the “ExL Acquisition”) in 2017 and divestitures of the Company’s assets in the Niobrara in 2018, and Marcellus and Utica in 2017, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the tables below. If the pricing threshold for the respective contingent consideration arrangement is met, the payment is made or received in the first quarter of the following year. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for further discussion of these transactions. See “—Cash received (paid) for settlements of contingent consideration arrangements, net” below for discussion of the settlements that occurred during the first quarter of 2019.
Contingent ExL Consideration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Threshold
(1)
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Contingent
Payment -
Annual
|
|
Remaining Contingent
Payments -
Aggregate Limit
|
|
Acquisition
Date
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($52,300
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Settlement
|
|
2018
|
|
|
$50.00
|
|
|
1Q19
|
|
Financing
|
|
|
($50,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Potential Settlements
|
|
2019-2021
|
|
50.00
|
|
|
(2)
|
|
(2)
|
|
(50,000
|
)
|
|
|
($75,000
|
)
|
|
|
|
|
|
|
(1)
|
The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).
|
|
|
|
|
(2)
|
Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached,
$2.3 million
of the next contingent payment will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent payments, presented in cash flows from operating activities.
|
Contingent Niobrara Consideration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Threshold
(1)
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Contingent
Receipt -
Annual
|
|
Remaining Contingent
Payments -
Aggregate Limit
|
|
Divestiture
Date
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$7,880
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Settlement
|
|
2018
|
|
$55.00
|
|
1Q19
|
|
Financing
|
|
|
$5,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Potential Settlements
|
|
2019
|
|
55.00
|
|
1Q20
|
|
(2)
|
|
5,000
|
|
|
|
$10,000
|
|
|
|
|
|
|
2020
|
|
60.00
|
|
1Q21
|
|
(2)
|
|
5,000
|
|
|
|
|
|
|
|
|
|
(1)
|
The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.
|
|
|
|
|
(2)
|
If the commodity price threshold is reached,
$2.9 million
of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.
|
Contingent Marcellus Consideration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Threshold
(1)
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Contingent
Receipt -
Annual
|
|
Remaining Contingent
Payments -
Aggregate Limit
|
|
Divestiture
Date
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$2,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Settlement
|
|
2018
|
|
$3.13
|
|
1Q19
|
|
N/A
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Potential Settlements
|
|
2019
|
|
3.18
|
|
1Q20
|
|
(2)
|
|
3,000
|
|
|
|
$6,000
|
|
|
|
|
|
|
2020
|
|
3.30
|
|
1Q21
|
|
(2)
|
|
3,000
|
|
|
|
|
|
|
|
|
|
(1)
|
The price used to determine whether the specified threshold for each year has been met 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.
|
|
|
|
|
(2)
|
For the first quarter of
2019
, there was no settlement for the Contingent Marcellus Consideration. Therefore, if the commodity price threshold is reached,
$2.7 million
of the contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.
|
Contingent Utica Consideration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Threshold
(1)
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Contingent
Receipt -
Annual
|
|
Remaining Contingent
Payments -
Aggregate Limit
|
|
Divestiture
Date
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$6,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Settlement
|
|
2018
|
|
$50.00
|
|
1Q19
|
|
Financing
|
|
|
$5,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Potential Settlements
|
|
2019
|
|
53.00
|
|
1Q20
|
|
(2)
|
|
5,000
|
|
|
|
$10,000
|
|
|
|
|
|
|
2020
|
|
56.00
|
|
1Q21
|
|
(2)
|
|
5,000
|
|
|
|
|
|
|
|
|
|
(1)
|
The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.
|
|
|
|
|
(2)
|
If the commodity price threshold is reached,
$1.1 million
of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.
|
Derivative Assets and Liabilities
The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of
June 30, 2019
and
December 31, 2018
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
|
|
|
(In thousands)
|
|
Commodity derivative instruments
|
|
|
$21,704
|
|
|
|
($15,582
|
)
|
|
|
$6,122
|
|
|
Contingent Niobrara Consideration
|
|
3,409
|
|
|
—
|
|
|
3,409
|
|
|
Contingent Marcellus Consideration
|
|
3
|
|
|
—
|
|
|
3
|
|
|
Contingent Utica Consideration
|
|
4,087
|
|
|
—
|
|
|
4,087
|
|
|
Derivative assets
|
|
|
$29,203
|
|
|
|
($15,582
|
)
|
|
|
$13,621
|
|
|
Commodity derivative instruments
|
|
10,303
|
|
|
(8,243
|
)
|
|
2,060
|
|
|
Contingent Niobrara Consideration
|
|
1,538
|
|
|
—
|
|
|
1,538
|
|
|
Contingent Marcellus Consideration
|
|
447
|
|
|
—
|
|
|
447
|
|
|
Contingent Utica Consideration
|
|
1,970
|
|
|
—
|
|
|
1,970
|
|
|
Other long-term assets
|
|
|
$14,258
|
|
|
|
($8,243
|
)
|
|
|
$6,015
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($26,390
|
)
|
|
|
$8,024
|
|
|
|
($18,366
|
)
|
|
Deferred premium obligations
|
|
(7,558
|
)
|
|
7,558
|
|
|
—
|
|
|
Contingent ExL Consideration
|
|
(46,385
|
)
|
|
—
|
|
|
(46,385
|
)
|
|
Derivative liabilities-current
|
|
|
($80,333
|
)
|
|
|
$15,582
|
|
|
|
($64,751
|
)
|
|
Commodity derivative instruments
|
|
(10,988
|
)
|
|
6,474
|
|
|
(4,514
|
)
|
|
Deferred premium obligations
|
|
(1,769
|
)
|
|
1,769
|
|
|
—
|
|
|
Contingent ExL Consideration
|
|
(14,413
|
)
|
|
—
|
|
|
(14,413
|
)
|
|
Other long-term liabilities
|
|
|
($27,170
|
)
|
|
|
$8,243
|
|
|
|
($18,927
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 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
|
|
|
$50,406
|
|
|
|
($20,502
|
)
|
|
|
$29,904
|
|
|
Contingent Niobrara Consideration
|
|
5,000
|
|
|
—
|
|
|
5,000
|
|
|
Contingent Utica Consideration
|
|
5,000
|
|
|
—
|
|
|
5,000
|
|
|
Derivative assets
|
|
|
$60,406
|
|
|
|
($20,502
|
)
|
|
|
$39,904
|
|
|
Commodity derivative instruments
|
|
6,083
|
|
|
(4,236
|
)
|
|
1,847
|
|
|
Contingent Niobrara Consideration
|
|
2,035
|
|
|
—
|
|
|
2,035
|
|
|
Contingent Marcellus Consideration
|
|
1,369
|
|
|
—
|
|
|
1,369
|
|
|
Contingent Utica Consideration
|
|
2,501
|
|
|
—
|
|
|
2,501
|
|
|
Other long-term assets
|
|
|
$11,988
|
|
|
|
($4,236
|
)
|
|
|
$7,752
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
($15,345
|
)
|
|
|
$10,140
|
|
|
|
($5,205
|
)
|
|
Deferred premium obligations
|
|
(10,362
|
)
|
|
10,362
|
|
|
—
|
|
|
Contingent ExL Consideration
|
|
(50,000
|
)
|
|
—
|
|
|
(50,000
|
)
|
|
Derivative liabilities-current
|
|
|
($75,707
|
)
|
|
|
$20,502
|
|
|
|
($55,205
|
)
|
|
Commodity derivative instruments
|
|
(10,751
|
)
|
|
518
|
|
|
(10,233
|
)
|
|
Deferred premium obligations
|
|
(3,718
|
)
|
|
3,718
|
|
|
—
|
|
|
Contingent ExL Consideration
|
|
(30,584
|
)
|
|
—
|
|
|
(30,584
|
)
|
|
Other long-term liabilities
|
|
|
($45,053
|
)
|
|
|
$4,236
|
|
|
|
($40,817
|
)
|
See “Note
14.
Fair Value Measurements” for additional information regarding the fair value of the Company’s derivative instruments.
(Gain) loss on derivatives, net
The components of “(Gain) loss on derivatives, net” in the consolidated statements of income for the
three and six months ended June 30,
2019
and
2018
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
(Gain) loss on derivatives, net
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
($20,915
|
)
|
|
|
$53,437
|
|
|
|
$41,846
|
|
|
|
$82,948
|
|
|
NGL
|
|
—
|
|
|
6,564
|
|
|
(6
|
)
|
|
4,799
|
|
|
Natural gas
|
|
(1,600
|
)
|
|
153
|
|
|
(3,670
|
)
|
|
(2,892
|
)
|
|
Contingent ExL Consideration
|
|
1,215
|
|
|
10,600
|
|
|
30,214
|
|
|
16,430
|
|
|
Contingent Niobrara Consideration
|
|
265
|
|
|
(1,705
|
)
|
|
(2,912
|
)
|
|
(2,090
|
)
|
|
Contingent Marcellus Consideration
|
|
438
|
|
|
205
|
|
|
919
|
|
|
675
|
|
|
Contingent Utica Consideration
|
|
148
|
|
|
(1,540
|
)
|
|
(3,556
|
)
|
|
(2,560
|
)
|
|
(Gain) loss on derivatives, net
|
|
|
($20,449
|
)
|
|
|
$67,714
|
|
|
|
$62,835
|
|
|
|
$97,310
|
|
Cash received (paid) for derivative settlements, net
There were no settlements of contingent consideration arrangements for the three months ended June 30, 2019. For the
six months ended June 30,
2019
, the Company paid
$50.0 million
from the first annual settlement of the Contingent ExL Consideration and received
$10.0 million
from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. The cash paid and received for those contingent consideration settlements are classified as cash flows from financing activities as each of the settlements were less than their respective acquisition or divestiture date fair values. For the
three and six months ended June 30,
2018
, there were no settlements of contingent consideration arrangements.
The components of “Cash paid for derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” in the consolidated statements of cash flows for the
three and six months ended June 30,
2019
and
2018
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Cash Flows From Operating Activities
|
|
(In thousands)
|
|
Cash received (paid) for commodity derivative settlements, net
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
($3,698
|
)
|
|
|
($21,210
|
)
|
|
|
($4,018
|
)
|
|
|
($33,333
|
)
|
|
NGL
|
|
—
|
|
|
(756
|
)
|
|
623
|
|
|
(1,188
|
)
|
|
Natural gas
|
|
1,925
|
|
|
488
|
|
|
1,625
|
|
|
540
|
|
|
Deferred premium obligations
|
|
(2,749
|
)
|
|
(2,605
|
)
|
|
(5,390
|
)
|
|
(4,467
|
)
|
|
Cash paid for commodity derivative settlements, net
|
|
|
($4,522
|
)
|
|
|
($24,083
|
)
|
|
|
($7,160
|
)
|
|
|
($38,448
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
Cash received (paid) for settlements of contingent consideration arrangements, net
|
|
|
|
|
|
Contingent ExL Consideration
|
|
|
$—
|
|
|
|
$—
|
|
|
|
($50,000
|
)
|
|
|
$—
|
|
|
Contingent Niobrara Consideration
|
|
—
|
|
|
—
|
|
|
5,000
|
|
|
—
|
|
|
Contingent Utica Consideration
|
|
—
|
|
|
—
|
|
|
5,000
|
|
|
—
|
|
|
Cash paid for settlements of contingent consideration arrangements, net
|
|
|
$—
|
|
|
|
$—
|
|
|
|
($40,000
|
)
|
|
|
$—
|
|
14.
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
June 30, 2019
and
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
$8,182
|
|
|
|
$—
|
|
|
Contingent Niobrara Consideration
|
|
—
|
|
|
4,947
|
|
|
—
|
|
|
Contingent Marcellus Consideration
|
|
—
|
|
|
450
|
|
|
—
|
|
|
Contingent Utica Consideration
|
|
—
|
|
|
6,057
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
($22,880
|
)
|
|
|
$—
|
|
|
Contingent ExL Consideration
|
|
—
|
|
|
(60,798
|
)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
$31,751
|
|
|
|
$—
|
|
|
Contingent Niobrara Consideration
|
|
—
|
|
|
7,035
|
|
|
—
|
|
|
Contingent Marcellus Consideration
|
|
—
|
|
|
1,369
|
|
|
—
|
|
|
Contingent Utica Consideration
|
|
—
|
|
|
7,501
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
|
$—
|
|
|
|
($15,438
|
)
|
|
|
$—
|
|
|
Contingent ExL Consideration
|
|
—
|
|
|
(80,584
|
)
|
|
—
|
|
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.
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 liability. These inputs are substantially
observable in active markets throughout the full term of the contingent consideration arrangements or can be derived from observable data and are therefore designated as Level 2 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.
See “Note
13.
Derivative Instruments” for additional information regarding the contingent consideration arrangements.
The Company had
no
transfers into Level 1 and
no
transfers into or out of Level 2 for the
six months ended June 30,
2019
.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured 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
4.
Acquisitions and Divestitures of Oil and Gas Properties” for additional discussion.
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 the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company.
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 principal amounts of the Company’s senior notes and other long-term debt with the fair values measured using quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note
8.
Long-Term Debt” for additional discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
December 31, 2018
|
|
|
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
6.25% Senior Notes due 2023
|
|
|
$650,000
|
|
|
|
$626,438
|
|
|
|
$650,000
|
|
|
|
$599,625
|
|
|
8.25% Senior Notes due 2025
|
|
250,000
|
|
|
244,063
|
|
|
250,000
|
|
|
244,375
|
|
15.
Supplemental Cash Flow Information
Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
Operating activities:
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
|
$34,475
|
|
|
|
$29,853
|
|
|
Cash paid for income taxes
|
|
590
|
|
|
—
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
Increase (decrease) in capital expenditure payables and accruals
|
|
|
$28,428
|
|
|
|
$35,543
|
|
|
|
|
|
|
|
|
Supplemental non-cash investing activities:
|
|
|
|
|
|
Fair value of contingent consideration assets on date of divestiture
|
|
|
$—
|
|
|
|
($7,880
|
)
|
|
Stock-based compensation expense capitalized to oil and gas properties
|
|
3,417
|
|
|
4,416
|
|
|
Asset retirement obligations capitalized to oil and gas properties
|
|
3,324
|
|
|
691
|
|
|
|
|
|
|
|
|
Supplemental non-cash financing activities:
|
|
|
|
|
|
Non-cash loss on extinguishment of debt, net
|
|
|
$—
|
|
|
|
$2,666
|
|
16.
Subsequent Events
On July 14, 2019, the Company entered into the Merger Agreement with Callon. See “Note
1.
Nature of Operations” for further discussion.