NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Business and Organization
Extraction Oil & Gas, Inc. (the "Company" or "Extraction") is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the "DJ Basin") of Colorado, as well as the construction and support of midstream assets to gather and process crude oil and gas production. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG."
Elevation Midstream, LLC ("Elevation"), a Delaware limited liability company and an unrestricted subsidiary of the Company, is focused on the construction and operation of gathering systems and facilities to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the consolidated balance sheet.
Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company, including its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States ("GAAP").
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. On an on-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables as of or for the years ended December 31, 2019 and 2018.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.
The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the years ended December 31, 2019, 2018 and 2017, respectively, the Company had the following customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.
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For the Year Ended December 31,
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2019
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|
2018
|
|
2017
|
|
Customer A
|
77
|
%
|
|
76
|
%
|
|
65
|
%
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|
Customer B
|
—
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%
|
|
11
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%
|
|
19
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%
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|
Customer C
|
—
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%
|
|
—
|
%
|
|
11
|
%
|
At December 31, 2019, the Company had commodity derivative contracts with ten counterparties, all of whom are lenders under our credit agreement. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. For the years ended December 31, 2019, 2018 and 2017, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit-risk related contingent features.
Inventory, Prepaid Expenses and Other
The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Inventory, prepaid expenses and other are comprised of the following (in thousands):
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As of December 31,
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2019
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2018
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|
Well equipment inventory
|
$
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20,960
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|
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$
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19,916
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|
|
Prepaid expenses
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5,793
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|
|
6,900
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Contractual asset under ASC 606
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9,949
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|
—
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|
|
|
$
|
36,702
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|
|
$
|
26,816
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|
Additionally, the Company recognized impairment expense on well equipment inventory in the amount of $0.1 million and $0.7 million for the years ended December 31, 2018 and 2017, respectively. No such impairment expense was recognized for the year ended December 31, 2019.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years ended
December 31, 2019, 2018 and 2017, the Company excluded $149.7 million, $144.3 million and $127.4 million, respectively, of capitalized costs from depletion related to wells in progress. For the years ended December 31, 2019, 2018 and 2017, the Company recorded depletion expense on capitalized oil and gas properties of $513.7 million, $426.8 million and $306.7 million, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital-intensive nature
and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2019, the Company had no suspended well costs. As of December 31, 2018, the Company had $6.1 million of suspended well costs, all capitalized less than one year and included in wells in progress as of the balance sheet date. These exploratory well costs were pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves would be discovered. The Company completed its evaluation in 2019 and moved all of these suspended well costs to proved oil and gas properties based on the determination of proved reserves.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. The Company expensed $0.2 million, $0.4 million and $1.4 million of costs associated with exploratory geological and geophysical costs for the years ended December 31, 2019, 2018 and 2017, respectively.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2019, 2018 and 2017, the Company capitalized interest of approximately $7.2 million, $8.2 million and $11.1 million, respectively.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the year ended December 31, 2019, the Company recognized $14.5 million related to impairment of the proved oil and gas properties in its northern field and $1.3 billion related to assets in its Core DJ Basin field as the field's fair values did not exceed the carrying amounts associated with its proved oil and gas properties. For the year ended December 31, 2018, the Company recognized $16.2 million related to impairment of the proved oil and gas properties in its northern field as the fair value did not exceed the carrying amount associated with its proved oil and gas properties in its northern field. No impairment expense was recognized for the year ended December 31, 2018 on proved oil and gas properties in the Company's Core DJ Basin field. For the year ended December 31, 2017, the Company recognized no impairment expense on proved oil and gas properties.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, the Company recognized $73.7 million, $25.7 million and $15.8 million impairment expense for the years ended December 31, 2019, 2018 and 2017, respectively.
Other Property and Equipment
Other property and equipment consists of (i) compressors, compressor stations, central tank batteries and disposal well facilities used in Extraction’s oil and gas operations, (ii) land, (iii) rights of ways, pipeline and engineering costs, (iv) office leasehold improvements, (v) the field office, and (vi) other property and equipment including office furniture and fixtures and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets and goodwill in the consolidated statements of operations. The Company recognized $0.4 million and $0.9 million in impairment expense related to midstream facilities for the years ended December 31, 2018 and 2017, respectively, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. These impairment expenses were primarily the result of right-of-way options that were no longer in the Company's plans for developing midstream infrastructure. Impairment expense related to midstream facilities was less than $0.1 million for the year ended December 31, 2019. For relevant years, gain or loss on the sale of other property and equipment is reported in gain (loss) on sale of property and equipment and assets of unconsolidated subsidiary in the consolidated statements of operations. The Company recognized $0.5 million of loss on the sale of other property and equipment related to the disposal of an oil pipeline that was not yet placed into service in the first quarter of 2017. Other property and equipment is recorded at historical cost and depreciated using the straight-line method.
The estimated useful lives of those assets depreciated under the straight-line method are as follows:
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Rental equipment
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1-10 years
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Office leasehold improvements
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3-10 years
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Field office
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30 years
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Other
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3-5 years
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Other property and equipment is comprised of the following (in thousands):
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As of December 31,
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2019
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2018
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Rental equipment
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$
|
4,043
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|
|
$
|
4,043
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|
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Land
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42,273
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|
|
27,595
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Right-of-ways and pipeline
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8,008
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|
8,008
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Office leasehold improvements
|
7,009
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|
|
7,231
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Field office
|
18,317
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|
|
—
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|
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Other
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8,884
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|
|
6,946
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Less: accumulated depreciation and impairment
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(15,992)
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(13,974)
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|
|
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$
|
72,542
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|
|
$
|
39,849
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|
Gathering Systems and Facilities
Gathering systems and facilities consist of midstream assets such as land, rights of way, pipelines, equipment and construction and engineering costs associated with the construction of pipeline infrastructure to serve the development of the Company's acreage in its Hawkeye and Southwest Wattenberg areas. As of December 31, 2018, approximately $112.3 million of gathering systems and facilities assets had not been placed into service and therefore were not being depreciated during the year ended December 31, 2018. The majority of these assets were placed into service during the year ended December 31, 2019.
Gathering systems and facilities is comprised of the following (in thousands):
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As of December 31,
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2019
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2018
|
|
Gathering systems and facilities
|
$
|
314,906
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|
|
$
|
112,281
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|
Land associated with gathering systems and facilities
|
2,188
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|
2,188
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Less: accumulated depreciation
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(1,317)
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|
|
—
|
|
|
|
$
|
315,777
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|
|
$
|
114,469
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|
Gathering systems and facilities balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.
In assessing gathering systems and facilities assets for impairment, management evaluates changes in business and economic conditions and their implications for recoverability of the assets' carrying amounts. The measure of impairments to be recognized, if any, depends upon management's estimate of the asset's fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. Gathering systems and facilities are recorded at historical cost and depreciated using the straight-line method over 30 years.
Equity Method Investments
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method of accounting. The Company recorded $44.6 million and $15.5 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2019 and 2018, respectively. The Company recognized $2.3 million, $2.9 million and $0.4 million of net income from such investments, including the accretion of any basis difference between the carrying amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated statements of operations and equity in earnings of unconsolidated subsidiary, in which we have a minority ownership interest on the consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017, respectively.
For the year ended December 31, 2019, a gain on sale of unconsolidated subsidiary of $1.0 million was recorded relating to Elevation's August 2018 Divestiture. In August 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight-line basis as a reduction of rental expense.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company's credit facility, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes"). Debt issuance costs related to the credit facility are included in other non-current assets on the consolidated balance sheets and amortized to interest expense on the consolidated statement of operations on a straight-line basis over the respective borrowing term. Debt issuance costs related to the Senior Notes are amortized to interest expense using the effective interest method over the term of the debt.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivatives loss line on the consolidated statements of operations. The Company's cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the Company's consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash
received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivative contracts, and the cash received is reflected in cash flows from operating activities in the Company's consolidated statements of cash flows.
The Company's valuation estimate takes into consideration the counterparties' credit worthiness, the Company's credit worthiness, and the time value of money. The consideration of these factors result in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 7 — Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Goodwill and Other Intangible Assets
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test was performed at the reporting unit level, which represented the Company’s oil and gas operations in its Core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas, as well as continued declines in the quoted market price of the Company’s common shares, could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. As such, no test for goodwill impairment was necessary for the year ended December 31, 2019.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license, which is typically one to three years. The Company recorded $2.2 million, $3.0 million and $2.3 million of capitalized internal-use software costs for the years ended December 31, 2019, 2018 and 2017, respectively, on the consolidated balance sheets within the other non-current assets line item. Accumulated amortization for the years ended December 31, 2019 and 2018 was $5.3 million and $3.1 million, respectively. The Company recognized $2.2 million, $2.1 million and $1.0 million of amortization expense for the years ended December 31, 2019, 2018 and 2017, respectively.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 9 — Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 8 — Asset Retirement Obligations.
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no significant environmental liabilities existed as of December 31, 2019. Please refer to Note 14 — Commitments and Contingencies for additional discussion on environmental liabilities.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company recognizes revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2019 and 2018, the Company had oil imbalances of 12.7 and 22.0 MBbl, respectively, which the Company intends to settle with the counterparty in crude oil barrels. There was no material imbalance at December 31, 2017.
On January 1, 2018, the Company adopted ASC 606 - Revenue from Contracts with Customers ("ASC 606"). See Adoption of ASC 606 for more information regarding the adoption of this standard.
Stock-Based Payments
The Company has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards which therefore required the Company to recognize the expense in its financial statements.
All stock-based payments to directors, officers and employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 12 — Stock-Based Compensation for additional discussion on stock-based payments.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. We believe it is more likely than not that the benefit from net operating loss carryforwards will not be fully realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company does not currently have uncertain tax positions.
Earnings Per Share
Basic earnings per share ("EPS") includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the "if-converted" method to determine the potential dilutive effects of its Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards.
Segment Reporting
Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. Revenues and operating expenses associated with the gathering systems and facilities operations are derived from intersegment transactions for services provided to our exploration, development and production operations as well as third parties. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity. The activity of the exploration and production segment and gathering systems and facilities segment are being monitored by our chief operating decision maker ("CODM"). Revenues associated with the exploration and production segment are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Revenues and operating expenses associated with the gathering and facilities segment are derived from intersegment transactions for services provided to the Company's exploration, development and production operations by Elevation Midstream, LLC., an unrestricted subsidiary to the Company, as well as third parties. In October 2019, Elevation commenced moving crude oil, natural gas and water through their newly constructed Badger central gathering facility. This facility enables Extraction and will enable others to efficiently transport crude oil and natural gas production along with water used during the completion process. The use of this gathering facility allows for the elimination of oil or water storage on well pad site and reduces truck traffic, which minimizes the impact to the surrounding environment and communities. Intersegment transactions are eliminated upon consolidation, including revenues and operating expenses during the construction of and from gathering services provided by Elevation to the Company. The CODM considers Adjusted EBITDAX as the measure of segment performance under ASC 280, Segment Reporting. Accounting policies for each segment are the same as the accounting policies as described herein. For more information about Segments, see Note 16 — Segment Information.
All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related disclosures.
In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company plans to adopt this standard by the effective date and believes adoption will have an immaterial impact to the consolidated financial statements and related disclosures.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU No. 2016-13 was subsequently amended by ASU No. 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU No.
2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU No. 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company plans to adopt this standard by the effective date and believes adoption will have an immaterial impact to the consolidated financial statements and related disclosures as the Company does not have a history of material credit losses.
In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company plans to adopt this standard by the effective date and believes adoption will have an immaterial impact to the consolidated financial statements and related disclosures.
In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.
In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations.
In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption had no impact for the periods presented on the Company’s consolidated statements of cash flows, results of operations or financial position in this Annual Report.
In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there was no impact to the total change in cash and cash equivalents from period to period.
In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Under the new standard, certain lease agreements with terms over one year are classified as right-of-use assets and right-of-use liabilities, which gross up the balance sheet. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company adopted these lease accounting standards on January 1, 2019 using a modified retrospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. Upon adoption, the Company elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things,
requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheets. Please refer to Note 5 — Leases for further information.
In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14 and ASU No. 2019-20, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more information.
Adoption of ASC 606
On January 1, 2018, the Company adopted ASC 606. The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.
Changes to sales of natural gas and NGL, as well as transportation and gathering expenses, are due to the conclusion that certain midstream processing entities are the Company's customers in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity. Revenues from the sale of oil, natural gas and NGL, where the Company is a non-operating interest partner, are considered in the scope of ASC 808 - Collaborative Arrangements. Therefore, ASC 606 did not change the presentation of these revenues.
Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense.
Revenues from Contracts with Customers
Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.
Oil Sales
Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.
The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under ASC 606. As of December 31, 2019, the Company had an oil imbalance of 12.7 MBbl, which the Company intends to settle with the counterparty in crude oil barrels.
Natural Gas and NGL Sales
Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGL and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations.
Performance Obligations
A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less.
For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally 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.
The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer.
Contract Balances
The Company has a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract begins an automatic month-to-month renewal unless terminated by either party giving notice at least 180 days prior to the effective termination date but in no event can either party give such notice earlier than November 1, 2020. Based on the accounting treatment pursuant to ASC 606 - Revenue from Contracts with Customers, the contract term ends on April 30, 2021 because it may be terminated by either party with no penalty effective as of such date. The contract term impacts the amount of consideration that can be included in the transaction price. Generally, under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. For the year ended December 31, 2019, the Company allocated $24.7 million to a satisfied performance obligation recognized within oil sales under ASC 606. As of December 31, 2019, the Company estimated a performance obligation under ASC 606 of $38.2 million, of which $3.9 million is recorded in accounts payable and accrued liabilities and $34.3 million is recorded in other non-current liabilities. A corresponding asset was recorded in the amount of $13.5 million, of which $9.9 million is recorded in inventory, prepaid expenses and other and $3.6 million is recorded in other non-current assets. The asset will be amortized into revenue over the contractual term of the contract, and the liability will be relieved if a deficiency payment is made to the counterparty or when the Company's minimum volume commitments are fulfilled.
The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017(1)
|
|
Revenues:
|
|
|
|
|
|
|
Oil sales
|
$
|
721,429
|
|
|
$
|
840,687
|
|
|
$
|
419,904
|
|
|
Natural gas sales
|
129,969
|
|
|
121,180
|
|
|
92,322
|
|
|
NGL sales
|
92,429
|
|
|
134,558
|
|
|
92,070
|
|
|
Gathering and compression
|
1,261
|
|
|
—
|
|
|
—
|
|
|
Transportation and gathering included in revenues
|
(38,453)
|
|
|
(35,682)
|
|
|
—
|
|
|
Total Revenues
|
$
|
906,635
|
|
|
$
|
1,060,743
|
|
|
$
|
604,296
|
|
(1) Revenue during and for the year ended December 31, 2017 was accounted for under ASC 605, Revenue Recognition.
There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2019 and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures.
Note 3—Oil and Gas Properties
The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
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|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
2019
|
|
2018
|
|
Proved oil and gas properties
|
$
|
4,530,934
|
|
|
$
|
3,916,622
|
|
|
Unproved oil and gas properties(1)
|
524,214
|
|
|
609,284
|
|
|
Wells in progress(2)
|
149,733
|
|
|
144,323
|
|
|
Total capitalized costs(3)
|
$
|
5,204,881
|
|
|
$
|
4,670,229
|
|
|
Accumulated depletion, depreciation, amortization and impairment charge(4)
|
(2,985,983)
|
|
|
(1,152,590)
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|
|
Net capitalized costs
|
$
|
2,218,898
|
|
|
$
|
3,517,639
|
|
(1)Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined.
(2)Costs from wells in progress are excluded from the amortization base until production commences.
(3)Includes accumulated interest capitalized of $39.8 million and $32.6 million as of December 31, 2019 and 2018, respectively.
(4)For more information about proved oil and gas properties impairment, see Note 2 — Basis of Presentation and Significant Accounting Policies.
The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands):
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|
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|
|
|
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|
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For the Year Ended
|
|
|
|
|
December 31,
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|
|
|
|
2019
|
|
2018
|
|
Property acquisition costs:
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|
|
|
|
Proved
|
$
|
21,024
|
|
|
$
|
46,052
|
|
|
Unproved
|
35,207
|
|
|
79,708
|
|
|
Exploration costs(1)
|
3,569
|
|
|
8,840
|
|
|
Development costs
|
588,974
|
|
|
776,528
|
|
|
Total
|
$
|
648,773
|
|
|
$
|
911,128
|
|
|
Total excluding asset retirement costs
|
$
|
598,778
|
|
|
$
|
902,241
|
|
(1)Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line item exploration and abandonment expenses in the consolidated statements of operations.
Note 4—Acquisitions and Divestitures
February 2020 Divestiture
In February 2020, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $14.7 million, subject to customary purchase price adjustments. The Company continues to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.
December 2019 Divestiture
In December 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $10.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the December 2019 Divestiture.
August 2019 Divestiture
In August 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the August 2019 Divestiture.
March 2019 Divestiture
In March 2019, the Company completed the sale of its interests in approximately 5,000 net acres of leasehold and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture.
As of December 31, 2018, these assets were classified as held for sale. The following table presents the information related to the assets held for sale in the December 31, 2018 consolidated balance sheet (in thousands):
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|
|
|
|
|
|
|
|
December 31, 2018
|
|
Assets:
|
|
|
Property and equipment
|
|
|
Proved oil and gas properties, net
|
$
|
11,945
|
|
|
Unproved oil and gas properties
|
9,063
|
|
|
Total Assets Held for Sale
|
$
|
21,008
|
|
|
|
|
|
Liabilities:
|
|
|
Revenue payable
|
$
|
1,737
|
|
|
Production taxes payable
|
1,409
|
|
|
Total Liabilities Held for Sale
|
$
|
3,146
|
|
|
Total Assets Held for Sale, Net
|
$
|
17,862
|
|
The assets held for sale as of December 31, 2018 do not qualify for discontinued operations as they do not represent a strategic shift that will have a major effect of the Company's operations or financial results.
December 2018 Divestitures
In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million, subject to customary purchase price adjustments, and recognized a loss of $6.1 million.
August 2018 Divestiture
In August 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
April 2018 Divestitures
In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3 million for the year ended December 31, 2018.
April 2018 Acquisition
In April 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-producing leasehold primarily located in Arapahoe County, Colorado (the "April 2018 Acquisition"). Upon closing the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
January 2018 Acquisition
On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of non-producing leasehold located in Arapahoe County, Colorado, (the "January 2018 Acquisition"). Upon closing the seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
November 2017 Acquisition
On November 15, 2017, the Company acquired an unaffiliated oil and gas company's interest in approximately 36,600 net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. This
transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
July 2017 Acquisition
On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold and primarily non-producing properties located primarily in Adams County, Colorado, (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
June 2017 Acquisition
On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the "June 2017 Acquisition"). The Company paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated as of the closing date of June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties contributed $3.3 million of revenue and $2.5 million of earnings, respectively, for the year ended December 31, 2018. The acquired producing properties contributed $3.7 million of revenue and $3.0 million of earnings, respectively, for the year ended December 31, 2017. No significant transaction costs related to the acquisition were incurred for the years ended December 31, 2019, 2018 and 2017.
The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
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|
|
|
|
|
|
|
|
|
|
Purchase Price
|
|
June 8, 2017
|
|
Consideration given
|
|
|
|
Cash
|
|
$
|
13,395
|
|
|
Total consideration given
|
|
$
|
13,395
|
|
|
Allocation of Purchase Price
|
|
|
|
Proved oil and gas properties
|
|
$
|
13,495
|
|
|
Total fair value of oil and gas properties acquired
|
|
13,495
|
|
|
Asset retirement obligations
|
|
(100)
|
|
|
Fair Value of Net Assets Acquired
|
|
$
|
13,395
|
|
Pro forma financial information is not provided for the June 2017 Acquisition as all adjustments were determined to be insignificant.
Note 5—Leases
The Company accounts for leases in accordance with ASC 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption (see "Recent Accounting Pronouncements" for impacts of adoption).
The Company enters into operating leases for certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, office facilities, compressors and office equipment. Under ASC 842, a contract is or contains a lease when (i) the contract contains an explicitly or implicitly identified asset and (ii) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. All leases (operating leases), other than those that qualify for the short-term recognition exemption, are recognized as of the lease commencement date on the balance sheet as a liability for its obligation related to the lease and a corresponding asset representing its right to use the underlying asset over the period of use.
The Company's leases have remaining terms up to nine years. Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that the Company will exercise an option at commencement, it considers various economic factors, including capital expenditure strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, the Company generally determines that the exercise of renewal options would not be reasonably certain in determining the expected lease term for leases, other than certain operating compressor leases.
The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As the Company's leases generally do not provide an implicit rate, the Company uses its incremental borrowing rate based on its revolving credit facility, which includes consideration of the nature, term, and geographic location of the leased asset.
Certain of the Company's leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of the Company's lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of the Company's lease assets and liabilities and are recognized in the period in which the obligation for those payments is incurred. The Company's lease agreements do not contain any material residual value guarantees or material restrictive covenants.
The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the consolidated statements of operations on a straight-line basis over the lease term. The Company has also made the election, for its certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, compressors and office equipment classes of underlying assets, to account for lease and non-lease components in a contract as a single lease component.
For the year ended December 31, 2019, lease costs, which represent the straight-line lease expense of right-of-use ("ROU") assets and short-term leases, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2019
|
|
Lease Costs included in the Consolidated Balance Sheets
|
|
|
Proved oil and gas properties, including drilling, completions and ancillary equipment, and gathering systems and facilities(1)
|
$
|
259,737
|
|
|
|
|
|
|
Lease Costs included in the Consolidated Statements of Operations
|
|
|
|
Operating lease costs(2)
|
$
|
33,025
|
|
|
General and administrative expenses(3)
|
3,821
|
|
|
Total operating lease costs
|
$
|
36,846
|
|
|
|
|
|
Total lease costs
|
$
|
296,583
|
|
(1) Represents short-term lease capital expenditures related to drilling rigs, completions equipment and other equipment ancillary to the drilling and completion of wells.
(2) Includes $8.8 million of lease costs accounted for under ASC 842.
(3) Includes $1.4 million of lease costs accounted for under ASC 842.
Supplemental cash flow information related to operating leases for the year ended December 31, 2019, was as follows (in thousands):
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2019
|
|
Cash paid for amounts included in the measurements of lease liabilities
|
|
|
Operating cash flows from operating leases
|
$
|
12,923
|
|
|
Right-of-use assets obtained in exchange for lease obligations
|
|
|
Operating leases
|
$
|
12,805
|
|
Supplemental balance sheet information related to operating leases as of December 31, 2019, were as follows (in thousands, except lease term and discount rate):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Classification
|
|
As of
December 31, 2019
|
|
Operating Leases
|
|
|
|
|
Operating lease right-of-use assets
|
Other non-current assets
|
|
$
|
29,186
|
|
|
|
|
|
|
|
Operating lease obligation - short-term
|
Accounts payable and accrued liabilities
|
|
17,388
|
|
|
Operating lease obligation - long-term
|
Other non-current liabilities
|
|
17,166
|
|
|
Total operating lease liabilities
|
|
|
$
|
34,554
|
|
|
|
|
|
|
|
Weighted Average Remaining Lease Term in Years
|
|
|
|
|
Operating leases
|
|
|
4.4
|
|
Weighted Average Discount Rate
|
|
|
|
|
Operating leases
|
|
|
4.2
|
%
|
As of December 31, 2019, the Company was subject to commitments on two drilling rig contracts one of which is contracted through February 2021. As of December 31, 2019, the Company had an insignificant amount of additional operating leases that have not yet commenced, of which none included involvement with the construction or design of the underlying asset.
Note 6—Long-Term Debt
As of the dates indicated in the table below, the Company’s long-term debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
2019
|
|
2018
|
|
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)
|
$
|
470,000
|
|
|
$
|
285,000
|
|
|
2024 Senior Notes due May 15, 2024
|
400,000
|
|
|
400,000
|
|
|
2026 Senior Notes due February 1, 2026
|
700,189
|
|
|
750,000
|
|
|
Unamortized debt issuance costs on Senior Notes
|
(14,412)
|
|
|
(17,341)
|
|
|
Total long-term debt
|
1,555,777
|
|
|
1,417,659
|
|
|
Less: current portion of long-term debt
|
—
|
|
|
—
|
|
|
Total long-term debt, net of current portion
|
$
|
1,555,777
|
|
|
$
|
1,417,659
|
|
Credit Facility
In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted
into common equity or redeemed prior to April 15, 2021 (the Company can redeem at any time), and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (c) the earlier termination in whole of the commitments. No principal payments are generally required until the credit agreement matures or in the event that the borrowing base falls below the outstanding balance.
In January 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $525.0 million to $750.0 million, subject to the current elected commitments of $650.0 million, (ii) increase the maximum amount for the letter of credit issued in favor of a purchaser of its crude oil from $25.0 million to $35.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. In connection with the 2026 Senior Notes Offering (as defined below), the borrowing base was automatically reduced to $700.0 million; however, the current elected commitments remained at $650.0 million.
In February 2018, the Company entered into a consent agreement and amended its revolving credit facility to (i) provide for consent by the lenders to (a) the designation of Elevation as an unrestricted subsidiary and (b) the transfer of certain assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain transportation service agreements with such unrestricted subsidiary.
In May 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $700.0 million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable interest rate margins for borrowings by 0.50%.
In October 2018, the Company amended its revolving credit facility to (i) postpone the November 1, 2018 scheduled borrowing base redetermination until December 15, 2018 and (ii) permit the Company to make payments with respect to its own equity, subject to certain terms, conditions and financial thresholds.
In December 2018, the Company's revolving credit facility was redetermined to increase the borrowing base from $800.0 million to $1.2 billion, associated with the postponed November 1, 2018 scheduled borrowing base determination. The current elected commitments remained at $650.0 million.
In January 2019, the Company amended its revolving credit facility to permit prepayments and redemptions of its unsecured bonds, subject to certain terms, conditions and financial thresholds.
In June 2019, the Company amended its revolving credit facility to (i) increase the elected commitments from $650.0 million to $900.0 million, (ii) increase the amount for permitted letters of credit from $50.0 million to $100.0 million and increase in the letter of credit for the Company's oil marketer from $35.0 million to $40.0 million, (iii) decrease the borrowing base from $1.2 billion to $1.1 billion and (iv) increase the limitation on permitted investments from $15.0 million to $20.0 million.
In August 2019, the Company amended its revolving credit facility to increase the elected commitments from $900.0 million to $1.0 billion.
In November 2019, the Company's revolving credit facility was redetermined to decrease the borrowing base from $1.1 billion to $950.0 million, associated with the scheduled borrowing base redetermination. The current elected commitments were also decreased to $950.0 million.
As of December 31, 2019, the credit facility was subject to a borrowing base of $950.0 million, subject to current elected commitments of $950.0 million. As of December 31, 2019, the Company had $470.0 million of borrowings outstanding. As of December 31, 2018, the Company had $285.0 million outstanding borrowings. As of December 31, 2019 and 2018, the Company had standby letters of credit of $49.5 million and $35.7 million, respectively, which reduces the availability of the undrawn borrowing base. At December 31, 2019, the undrawn balance under the credit facility was $430.5 million after considering letters of credit and is constrained by the Company's quantitative quarterly covenants under the credit facility, including the current ratio and ratio of consolidated debt less cash balances to its consolidated EBITDAX. As of the date of this filing, the Company had $470.0 million borrowings outstanding under the credit facility.
The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company's proved oil and gas reserves, commodity prices, estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company's revolving credit facility.
Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The weighted average interest rate for the years ending December 31, 2019 and 2018 was 4.8% and 5.1%, respectively. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing:
Borrowing Base Utilization Grid
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eurodollar
|
|
Base Rate
|
|
Commitment
|
|
Borrowing Base Utilization Percentage
|
|
Utilization
|
|
|
|
|
Margin
|
|
Margin
|
|
Fee Rate
|
|
Level 1
|
|
<25%
|
|
|
|
|
1.50
|
%
|
|
0.50
|
%
|
|
0.38
|
%
|
|
Level 2
|
|
≥
|
25%
|
<
|
50%
|
|
|
1.75
|
%
|
|
0.75
|
%
|
|
0.38
|
%
|
|
Level 3
|
|
≥
|
50%
|
<
|
75%
|
|
|
2.00
|
%
|
|
1.00
|
%
|
|
0.50
|
%
|
|
Level 4
|
|
≥
|
75%
|
<
|
90%
|
|
|
2.25
|
%
|
|
1.25
|
%
|
|
0.50
|
%
|
|
Level 5
|
|
≥90%
|
|
|
|
|
2.50
|
%
|
|
1.50
|
%
|
|
0.50
|
%
|
The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company entering into hedges in excess of 85% of its anticipated production volumes.
The credit facility also contains financial covenants requiring the Company to comply on the last day of each quarter with a current ratio of its restricted subsidiaries’ current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its restricted subsidiaries’ current liabilities (excludes obligations under the revolving credit facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of its restricted subsidiaries’ debt less cash balances to its restricted subsidiaries EBITDAX (EBITDAX is defined as net income adjusted for interest expense, income tax expense/benefit, DD&A, exploration and abandonment expenses as well as certain non-recurring cash and non-cash charges and income (such as stock-based compensation expense, unrealized gains/losses on commodity derivatives and impairment of long-lived assets and goodwill), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the four fiscal quarter period most recently ended, of not greater than 4.0 to 1.0 as of the last day of such fiscal quarter. As of December 31, 2019, the Company was in compliance with the covenants under the credit agreement and expects to maintain compliance with the credit agreement covenants during 2020 assuming the Company is able to execute on the results consistent with the fourth quarter of 2019. The Company's 2020 capital program remains focused on generating free cash flow with an emphasis on strengthening liquidity and the balance sheet as the Company works to pay down debt. However, factors including those outside of the Company's control may prevent maintaining compliance with such covenants, including the net leverage ratio covenant, at future measurement dates in 2020 and beyond. Such factors may include commodity price declines, lack of liquidity in property and capital markets and the Company's inability to execute on its business plan. If the Company is unable to remain in compliance with financial and non-financial covenants, it intends to seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate. However, no assurances can be given that the Company will be able to obtain such relief. If any such covenant violations are not waived by the lenders and the Company cannot comply with such covenants, the Company will be in default, the lenders under the credit agreement and the holders of the Company's senior notes could declare all outstanding principal and interest to be due and payable, and the lenders under the credit agreement could terminate their commitments to loan money and could foreclose against the assets collateralizing their borrowings.
Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of December 31, 2019, $10.7 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.
2021 Senior Notes
In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the "2021 Senior Notes" and the offering, the "2021 Senior Notes Offering"). The 2021 Senior Notes bore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.
Concurrent with the 2026 Senior Notes Offering (as defined below), the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million, which includes principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the "2024 Senior Notes" and the offering, the "2024 Senior Notes Offering"). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting fees.
The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the "2024 Senior Note Guarantors"). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the 2024 Senior Notes.
The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the "2024 Senior Notes Indenture") also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately.
2026 Senior Notes
In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the "2026 Senior Notes" and the offering, the "2026 Senior Notes Offering"). The 2026 Senior Notes bear an annual interest rate of 5.625%. The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.
The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness.
The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of certain of the Company's future restricted subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company's or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the "2026 Senior Notes Indenture") also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2026 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately.
Debt Issuance Costs
As of December 31, 2019 and 2018, the Company had debt issuance costs net of accumulated amortization of $2.9 million and $3.3 million, respectively, related to its credit facility which has been reflected on the Company’s consolidated balance sheet within the line item other non-current assets. As of December 31, 2019 and 2018, the Company had debt issuance costs net of accumulated amortization of $14.4 million and $17.3 million, respectively, related to its 2024 and 2026 Senior Notes, which have been reflected on the Company's consolidated balance sheets within the line item Senior Notes, net of unamortized debt issuance costs. Upon the redemption of the Company's 2021 Senior Notes in January and February 2018, the Company accelerated the amortization of the remaining $9.4 million of unamortized debt issuance costs. These expenses were recorded in the consolidated statements of operations within the interest expense line item. Debt issuance costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the years ended December 31, 2019, 2018, and 2017, the Company recorded amortization expense related to the debt issuance costs of $5.5 million, $13.2 million and $4.3 million, respectively.
Interest Incurred on Long-Term Debt
For the years ended December 31, 2019, 2018 and 2017, the Company incurred interest expense on long-term debt of $91.5 million, $82.7 million and $58.7 million, respectively, and the Company capitalized interest expense on long-term debt of $7.2 million, $8.2 million and $11.1 million, respectively, for the years ended December 31, 2019, 2018 and 2017, which has been reflected in the Company’s consolidated financial statements. Also included in interest expense for the year ended December 31, 2018 was a make-whole premium of $35.6 million related to the Company's repayment of its 2021 Senior Notes in January and February 2018. Also included in interest expense for the year ended December 31, 2017 is a prepayment penalty of $4.3 million related to the Company’s repayment of its Second Lien Notes in July 2016.
Senior Note Repurchase Program
On January 4, 2019, the Board of Directors authorized a program to repurchase up to $100.0 million of the Company’s Senior Notes. The Company’s Senior Notes Repurchase Program is subject to restrictions under the Credit Facility and does not obligate the Company to acquire any specific nominal amount of Senior Notes. During 2019, the Company repurchased 2026 Senior Notes with a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program. Interest expense for the year ended December 31, 2019 included a $10.5 million gain on debt repurchase related to the Company's Senior Note Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for the years ended December 31, 2018 and 2017.
Note 7—Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.
The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with ten counterparties, all of whom are lenders under our credit agreement. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There are no credit-risk-related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.
The Company’s commodity derivative contracts as of December 31, 2019 are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
NYMEX WTI Crude Swaps:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
3,200,000
|
|
|
3,900,000
|
|
|
1,020,000
|
|
|
|
900,000
|
|
|
Weighted average fixed price ($/Bbl)
|
$
|
59.81
|
|
|
$
|
57.17
|
|
|
$
|
54.84
|
|
|
|
$
|
54.87
|
|
|
NYMEX WTI Crude Purchased Puts:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
9,725,000
|
|
|
3,600,000
|
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average purchased put price ($/Bbl)
|
$
|
54.99
|
|
|
$
|
54.17
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
NYMEX WTI Crude Sold Calls:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
9,725,000
|
|
|
3,600,000
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average sold call price ($/Bbl)
|
$
|
62.04
|
|
|
$
|
61.93
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
NYMEX WTI Crude Sold Puts:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
12,250,000
|
|
|
7,500,000
|
|
|
600,000
|
|
|
|
600,000
|
|
|
Weighted average sold put price ($/Bbl)
|
$
|
42.91
|
|
|
$
|
43.28
|
|
|
$
|
43.00
|
|
|
|
$
|
43.00
|
|
|
NYMEX HH Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
35,400,000
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average fixed price ($/MMBtu)
|
$
|
2.75
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
NYMEX HH Natural Gas Purchased Puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
600,000
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average purchased put price ($/MMBtu)
|
$
|
2.90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
NYMEX HH Natural Gas Sold Calls:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
600,000
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average sold call price ($/MMBtu)
|
$
|
3.48
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
CIG Basis Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
45,600,000
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
Weighted average fixed basis price ($/MMBtu)
|
$
|
(0.61)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the balance sheets (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amounts of
|
|
|
|
|
|
|
|
Gross Amounts
|
|
|
|
Assets and
|
|
|
|
|
|
|
|
of Recognized
|
|
Gross Amounts
|
|
Liabilities
|
|
Gross Amounts
|
|
|
|
|
|
Assets and
|
|
Offset in the
|
|
Presented in the
|
|
not Offset in the
|
|
Net
|
|
Location on Balance Sheet
|
|
Liabilities
|
|
Balance Sheet(1)
|
|
Balance Sheet
|
|
Balance Sheet(2)
|
|
Amounts(3)
|
|
Current assets
|
|
$
|
48,605
|
|
|
$
|
(31,051)
|
|
|
$
|
17,554
|
|
|
$
|
—
|
|
|
$
|
30,783
|
|
|
Non-current assets
|
|
38,034
|
|
|
(24,805)
|
|
|
13,229
|
|
|
—
|
|
|
—
|
|
|
Current liabilities
|
|
(33,049)
|
|
|
31,051
|
|
|
(1,998)
|
|
|
—
|
|
|
(2,106)
|
|
|
Non-current liabilities
|
|
(24,913)
|
|
|
24,805
|
|
|
(108)
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Amounts of
|
|
|
|
|
|
|
|
Gross Amounts
|
|
|
|
Assets and
|
|
|
|
|
|
|
|
of Recognized
|
|
Gross Amounts
|
|
Liabilities
|
|
Gross Amounts
|
|
|
|
|
|
Assets and
|
|
Offset in the
|
|
Presented in the
|
|
not Offset in the
|
|
Net
|
|
Location on Balance Sheet
|
|
Liabilities
|
|
Balance Sheet(1)
|
|
Balance Sheet
|
|
Balance Sheet(2)
|
|
Amounts(3)
|
|
Current assets (4)
|
|
$
|
115,852
|
|
|
$
|
(66,945)
|
|
|
$
|
48,907
|
|
|
$
|
(192)
|
|
|
$
|
57,147
|
|
|
Non-current assets
|
|
17,217
|
|
|
(8,785)
|
|
|
8,432
|
|
|
—
|
|
|
—
|
|
|
Current liabilities (4)
|
|
(67,141)
|
|
|
66,945
|
|
|
(196)
|
|
|
192
|
|
|
(4)
|
|
|
Non-current liabilities
|
|
(8,785)
|
|
|
8,785
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2)Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement which are not netted on the balance sheet. There are no amounts of related financial collateral received or pledged.
(3)Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line, and all counterparties in a net liability position are shown in the current liability line.
(4)Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.
The table below sets forth the commodity derivatives loss for the years ended December 31, 2019, 2018 and 2017 (in thousands). Commodity derivatives loss are included under other income (expense).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Commodity derivatives loss
|
$
|
(37,107)
|
|
|
|
$
|
(8,554)
|
|
|
|
$
|
(36,332)
|
|
Note 8—Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.
The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
December 31,
|
|
|
|
|
2019
|
|
2018
|
|
Balance beginning of period
|
$
|
69,791
|
|
|
$
|
69,540
|
|
|
Liabilities incurred or acquired
|
978
|
|
|
2,136
|
|
|
Liabilities settled
|
(29,305)
|
|
|
(13,869)
|
|
|
Revisions in estimated cash flows(1)
|
49,050
|
|
|
6,800
|
|
|
Accretion expense
|
5,394
|
|
|
5,184
|
|
|
Balance end of period
|
$
|
95,908
|
|
|
$
|
69,791
|
|
(1)Revisions in estimated cash flows during the year ended December 31, 2019 and 2018 were primarily due to changes in estimates of costs to be incurred to plug and abandon wells and changes in estimated dates of abandonment.
Note 9—Fair Value Measurements
ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
•Level 1: Quoted prices are available in active markets for identical assets or liabilities;
•Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
•Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 by level within the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
Commodity derivative assets
|
$
|
—
|
|
|
$
|
30,783
|
|
|
$
|
—
|
|
|
$
|
30,783
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
$
|
—
|
|
|
$
|
2,106
|
|
|
$
|
—
|
|
|
$
|
2,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
Commodity derivative assets
|
$
|
—
|
|
|
$
|
57,339
|
|
|
$
|
—
|
|
|
$
|
57,339
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
$
|
—
|
|
|
$
|
196
|
|
|
$
|
—
|
|
|
$
|
196
|
|
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the tables above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the
instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company's credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair values of the 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to Note 6 — Long-Term Debt for further information. The Company's policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company's financial position, results of operations or cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2019
|
|
|
|
At December 31, 2018
|
|
|
|
|
Carrying
|
|
|
|
Carrying
|
|
|
|
|
Amount
|
|
Fair Value
|
|
Amount
|
|
Fair Value
|
|
Credit Facility
|
$
|
470,000
|
|
|
$
|
470,000
|
|
|
$
|
285,000
|
|
|
$
|
285,000
|
|
|
2024 Senior Notes(1)
|
394,824
|
|
|
250,000
|
|
|
393,866
|
|
|
330,000
|
|
|
2026 Senior Notes(2)
|
690,953
|
|
|
420,113
|
|
|
738,793
|
|
|
558,750
|
|
(1)The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $5.2 million and $6.1 million as of December 31, 2019 and 2018, respectively.
(2)The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $9.2 million and $11.2 million as of December 31, 2019 and 2018, respectively.
Non-Recurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on a recurring basis but are subject to fair value adjustments when facts and circumstances arise that indicate a need for remeasurement.
The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate, and at least annually, a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash flows of proved property. The Company calculates the estimated fair values of its proved property oil and gas assets using a discounted future cash flow model. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, and (v) a market-based weighted average cost of capital. The Company utilized the NYMEX strip pricing, adjusted for differentials, to value the reserves. These are classified as Level 3 fair value assumptions. At December 31, 2019, the Company’s estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2020 price of $59.03 per barrel of oil decreasing to a 2021 price of $54.38 per barrel of oil and decreasing further to a 2024 price of $51.44 per barrel of oil. Natural gas prices ranged from a 2020 price of $2.28 per Mcf increasing to a 2024 price of $2.49 per Mcf. NGL prices ranged from a 2020 price of $15.84 per barrel decreasing to a 2024 price of $13.80 per barrel. These prices were then adjusted for location and quality differentials. The expected future net cash flows were discounted using a rate of 11.6 percent.
For the years ended December 31, 2019 and 2018, respectively, the Company recognized $14.5 million and $16.2 million in impairment expense on its proved oil and gas properties related to assets in its northern field as the fair value did not exceed the Company's carrying amount attributable primarily to certain downward adjustments to the Company’s economically recoverable proved oil and natural gas reserves. For the year ended December 31, 2019, the Company recognized $1.3 billion in impairment expense on its proved oil and gas properties related to assets in its Core DJ Basin field as the fair value did not exceed the Company's carrying amount attributable primarily to certain downward adjustments to the Company’s reserves due to expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. No impairment expense was recognized for the year ended
December 31, 2018 on proved oil and gas properties in the Company's Core DJ Basin field. No impairment expense was recognized for the year ended December 31, 2017 on proved oil and gas properties.
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tested goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test was performed at the reporting unit level, which represented the Company’s oil and gas operations in its Core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. As such, no test for goodwill impairment was necessary for the year ended December 31, 2019.
The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using Level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non-recurring basis and is not measured in periods after initial recognition.
Note 10—Equity
Preferred Units
On July 3, 2018, Elevation entered into a securities purchase agreement (the "Securities Purchase Agreement") with a third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the "Elevation Preferred Units") of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the "Private Placement"), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the "Securities Act"). The Private Placement closed on July 3, 2018 (the "Preferred Unit Closing Date"), funded on July 19, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses.
On July 10, 2019, Elevation closed on the issuance of an additional 100,000 Preferred Units of Elevation under an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately $96.5 million, after deducting discounts and related offering expenses. The proceeds were to be used primarily for midstream capital expenditures.
These Preferred Units represent the noncontrolling interest presented on the consolidated balance sheets, consolidated statements of operations and consolidated statement of changes in stockholders' equity and noncontrolling interest. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of December 31, 2019, $10.7 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas. As of December 31, 2019 and 2018, Elevation capital expenditures represented all of the gathering systems and facilities line item in the consolidated balance sheets and the gathering systems and facilities additions in the consolidated statements of cash flows.
During the twenty-eight months following the Preferred Unit Closing Date (the "Preferred Unit Commitment Period"), Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment. For the years ended December 31, 2019 and 2018, respectively, Elevation recognized $3.1 million and $1.8 million of commitment fees paid-in-kind included under the Preferred
Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders' equity and noncontrolling interest. No such fees were recognized for the year ended December 31, 2017.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, such dividend is payable solely in cash. Elevation recognized $16.9 million and $5.5 million of dividends paid-in-kind for the years ended December 31, 2019 and 2018, respectively, included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders' equity and noncontrolling interest. No such fees were recognized for the year ended December 31, 2017.
Series A Preferred Stock and Series B Preferred Units
On October 3, 2016, the Company issued $185.3 million in convertible preferred securities ("Series B Preferred Units"). The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and the Company had the ability to pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units converted in connection with the closing of the IPO in October 2016 into 185,280 shares of Series A Convertible Preferred Stock (the "Series A Preferred Stock") that are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company has the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are paid in cash). During the first nine months of 2019, the Company incurred $8.2 million of dividends associated with the Series A Preferred Stock, or $44.13 per share. During the fourth quarter of 2019, the Company elected to pay the dividend in kind and increased the aggregate liquidation preference of the Series A Preferred Stock $4.6 million to $189.9 million. The Series A Preferred Stock is convertible into shares of our common stock at the election of the holders of the Series A Preferred Stock ("Series A Preferred Holders") at a conversion ratio per share of Series A Preferred Stock of 61.9195, and the Company may redeem the Series A Preferred Stock at any time for the liquidation preference, which is currently $189.9 million. In accordance with ASC Topic 470, Debt ("ASC 470"), the Company determined that the conversion feature of the Series A Preferred Stock represented a beneficial conversion feature. The fair value of the Company's common stock on the closing of the IPO was greater than the Series A Preferred Stock conversion price by approximately $32.7 million in aggregate. Under ASC 470, $32.7 million (the fair value of the beneficial conversion feature) of the proceeds received from the issuance of the Series B Preferred Units, subsequently converted to the Series A Preferred Stock, was allocated to additional paid-in capital. The beneficial conversion feature is required to be accreted on a non-cash basis over the approximate 60 month period between the issuance date and the required redemption date of October 15, 2021, or fully accreted upon an accelerated date of redemption or conversion, resulting in an increase of the Series A Convertible Preferred Stock presented on the Consolidated Balance Sheets. The accretion of the beneficial conversion feature of Series A Preferred Stock is presented as a decrease to additional paid-in capital on the changes in stockholders' equity and noncontrolling interest. As a result, approximately $6.6 million, $6.0 million and $5.4 million was accreted during the years ended December 31, 2019, 2018, and 2017, respectively. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash from funds legally available for such purpose in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Company and the Series A Preferred Stock Holders both have options to redeem the Series A Preferred Stock. The Company's option to convert the Series A Preferred Stock into common stock expired in October 2019. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. If the Series A Preferred Stock have not been converted into common equity or redeemed prior to April 15, 2021 (the Company can redeem at any time), the Company's Credit Facility will mature on April 15, 2021. For additional discussion, please see Note 6 — Long-Term Debt.
Stock Repurchase Program
On November 19, 2018, the Company announced that the Board of Directors had authorized a program to repurchase up to $100.0 million of the Company's common stock ("Stock Repurchase Program"). On April 1, 2019, the Company announced the Board of Directors had authorized an extension and increase to the ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million ("Extended Stock Repurchase Program"). The Stock Repurchase Program and the Extended Stock Repurchase Program were both completed during 2019, bringing the total amount of common stock repurchased to 38.2 million shares for $163.2 million and a weighted average share price of $4.27. For the years ended December 31, 2019 and 2018, the Company repurchased approximately 34.1 million and 4.1 million shares of its common stock for $137.0 million and $26.2 million, respectively.
Note 11—Income Taxes
At the end of 2017 the Tax Cuts and Jobs Act (the “TCJA") was enacted making significant changes to the Internal Revenue Code. As a result, the Company remeasured the deferred tax assets and liabilities as of December 31, 2017 at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and reflect a corresponding income tax benefit in the consolidated statement of operations for the year ended December 31, 2017. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA’s limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provision amount as of December 31, 2017. The Company believes that the accounting is complete regarding the revaluation of the deferred tax balances and there are no remaining provisional amounts associated with the TCJA as of December 31, 2018. The Company is aware that the Internal Revenue Service has issued proposed regulations regarding the TCJA and has incorporated this guidance into its current tax policy. The Company will continue to monitor and analyze the impact of future guidance and any final regulations as they become available.
The components of the income tax expense (benefit) were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Current:
|
|
|
|
|
|
|
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
State, net of federal benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
Total current income tax expense (benefit)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
$
|
(93,245)
|
|
|
$
|
56,943
|
|
|
$
|
(61,719)
|
|
|
State, net of federal benefit
|
(15,931)
|
|
|
9,907
|
|
|
(1,981)
|
|
|
Total deferred income tax expense (benefit)
|
$
|
(109,176)
|
|
|
$
|
66,850
|
|
|
$
|
(63,700)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
$
|
(109,176)
|
|
|
$
|
66,850
|
|
|
$
|
(63,700)
|
|
The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Net income (loss) before income taxes
|
$
|
(1,476,596)
|
|
|
$
|
188,705
|
|
|
$
|
(108,108)
|
|
|
Federal income taxes at statutory rate
|
(310,085)
|
|
|
39,628
|
|
|
(37,838)
|
|
|
State income taxes, net of federal benefit
|
(52,723)
|
|
|
9,907
|
|
|
(3,118)
|
|
|
Impact of goodwill impairment
|
—
|
|
|
11,386
|
|
|
—
|
|
|
Partnership income excluded
|
(3,558)
|
|
|
—
|
|
|
—
|
|
|
Nondeductible stock-based compensation
|
9,436
|
|
|
5,088
|
|
|
2,264
|
|
|
Enactment of the Tax Cuts and Jobs Act
|
—
|
|
|
—
|
|
|
(23,412)
|
|
|
Other
|
1,626
|
|
|
841
|
|
|
(1,596)
|
|
|
Valuation allowance
|
246,128
|
|
|
—
|
|
|
—
|
|
|
Income tax expense (benefit)
|
(109,176)
|
|
|
66,850
|
|
|
(63,700)
|
|
|
Net income (loss)
|
$
|
(1,367,420)
|
|
|
$
|
121,855
|
|
|
$
|
(44,408)
|
|
|
|
|
|
|
|
|
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
2019
|
|
2018
|
|
Deferred Tax Assets:
|
|
|
|
|
Net operating loss carryforward
|
$
|
266,446
|
|
|
$
|
149,399
|
|
|
Stock-based compensation
|
17,138
|
|
|
17,242
|
|
|
Intangible drilling costs - Section 59(e)
|
98,631
|
|
|
127,604
|
|
|
Property taxes
|
16,812
|
|
|
22,277
|
|
|
Other
|
—
|
|
|
10,856
|
|
|
Total deferred tax assets
|
$
|
399,027
|
|
|
$
|
327,378
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
Excess basis of oil and gas properties
|
$
|
(134,484)
|
|
|
$
|
(426,428)
|
|
|
Commodity derivatives
|
(7,071)
|
|
|
(10,126)
|
|
|
Other
|
(11,344)
|
|
|
—
|
|
|
Total deferred tax liabilities
|
(152,899)
|
|
|
(436,554)
|
|
|
Less: Valuation allowance
|
$
|
(246,128)
|
|
|
$
|
—
|
|
|
Deferred Taxes, net
|
$
|
—
|
|
|
$
|
(109,176)
|
|
Management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. The Company has net operating loss carryforwards (NOLs) for U.S. income tax purposes that have been generated from the Company's operations through December 31, 2019 of approximately $1.1 billion, of which $833.6 million was generated before January 1, 2018 and are not subject to the 80 percent limitation of taxable income. Such NOLs will expire beginning in 2036. As of December 31, 2019, the Company had $400.0 million of intangible drilling costs that were capitalized under Code Section 59(e). We believe it is more likely than not that the benefit from net operating loss carryforwards will not be fully realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets.
The utilization of such NOL carryforwards may be limited upon the occurrence of certain ownership changes as stipulated in Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"). As of December 31, 2019, the Company determined that the statutory provision of Section 382 will not limit the Company’s ability to realize future tax benefits. The Company files income tax returns in the U.S. federal jurisdiction and in Colorado. The statute of limitations related to the 2016, 2017 and 2018 tax returns is open through 2020, 2021 and 2022, respectively; however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized.
As of December 31, 2019, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there are any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of December 31, 2019, the Company had no provision for interest or penalties related to uncertain tax positions.
Note 12—Stock-Based Compensation
Extraction Long Term Incentive Plan
In October 2016, the Board of Directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the "2016 Plan" or "LTIP"), pursuant to which employees, consultants, and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In May 2019, the Company's stockholders approved the amendment and restatement of the Company's 2016 Long Term Incentive Plan. The amended and restated 2016 Long Term Incentive Plan provides a total reserve of 32.2 million shares of common stock for issuance pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards.
Restricted Stock Units
Restricted stock units ("RSUs") granted under the LTIP generally vest over either a one or three-year service period, with 100% vesting in year one or 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock pursuant to the terms of the LTIP. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.
The Company recorded $23.8 million, $27.9 million and $31.8 million of stock-based compensation costs related to RSUs for the years ended December 31, 2019, 2018 and 2017, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2019, there was $12.0 million of total unrecognized compensation costs related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 1.7 years.
The following table summarizes the RSU activity from January 1, 2017 through December 31, 2019 and provides information for RSUs outstanding at the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Shares
|
|
Fair Value
|
|
Non-vested RSUs at January 1, 2017
|
3,237,500
|
|
|
$
|
21.41
|
|
|
Granted
|
1,369,083
|
|
|
$
|
16.37
|
|
|
Forfeited
|
(445,366)
|
|
|
$
|
19.85
|
|
|
Vested
|
(1,254,744)
|
|
|
$
|
20.85
|
|
|
Non-vested RSUs at December 31, 2017
|
2,906,473
|
|
|
$
|
19.51
|
|
|
Granted
|
1,226,768
|
|
|
$
|
12.53
|
|
|
Forfeited
|
(95,725)
|
|
|
$
|
14.94
|
|
|
Vested
|
(935,181)
|
|
|
$
|
19.44
|
|
|
Non-vested RSUs at December 31, 2018
|
3,102,335
|
|
|
$
|
16.91
|
|
|
Granted
|
1,905,918
|
|
|
$
|
4.75
|
|
|
Forfeited
|
(469,035)
|
|
|
$
|
10.54
|
|
|
Vested
|
(1,903,453)
|
|
|
$
|
18.20
|
|
|
Non-vested RSUs at December 31, 2019
|
2,635,765
|
|
|
$
|
8.32
|
|
Performance Stock Awards
The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017, March 2018 and April 2019. The number of shares of the Company's common stock that may be issued to settle these various PSAs ranges from zero to two times the number of PSAs awarded. PSA's that settle in cash are presented as liability based awards. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) absolute total stockholder return ("ATSR"), (ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and (iii) cash return on capital invested ("CROCI") or return on invested capital ("ROIC") measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI and ROIC are considered a performance condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the
most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.
The assumptions used in valuing the PSAs granted were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
|
|
|
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
|
December 31, 2017
|
|
Risk free rates
|
2.3
|
%
|
|
2.3
|
%
|
|
1.5
|
%
|
|
Dividend yield
|
—
|
|
|
—
|
|
|
—
|
|
|
Expected volatility
|
58.5
|
%
|
|
59.9
|
%
|
|
45.0
|
%
|
The Company recorded $7.3 million, $5.7 million and $0.8 million of stock-based compensation costs related to PSAs for the years ended December 31, 2019, 2018 and 2017, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2019, there was $5.4 million of total unrecognized compensation costs related to the unvested PSAs granted to certain executives that is expected to be recognized over a weighted-average period of 1.2 years.
The following table summarizes the PSA activity from January 1, 2017 through December 31, 2019 and provides information for PSAs outstanding at the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Shares(1)
|
|
Fair Value
|
|
Non-vested PSAs as of January 1, 2017
|
—
|
|
|
$
|
—
|
|
|
Granted
|
832,163
|
|
|
$
|
8.85
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
Non-vested PSAs as of December 31, 2017
|
832,163
|
|
|
$
|
8.85
|
|
|
Granted
|
1,961,920
|
|
|
$
|
9.06
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
Non-vested PSAs as of December 31, 2018
|
2,794,083
|
|
|
$
|
9.00
|
|
|
Granted
|
1,224,696
|
|
|
$
|
5.63
|
|
|
Forfeited
|
(418,229)
|
|
|
$
|
8.17
|
|
|
Cancelled
|
(737,360)
|
|
|
$
|
8.85
|
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
Non-vested PSAs as of December 31, 2019
|
2,863,190
|
|
|
$
|
7.72
|
|
(1)The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to one for the 2017 and 2018 grants and ranges from zero to two for the 2019 grants, depending on the level of satisfaction of the vesting condition.
Stock Options
Expense on the stock options are recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black-Scholes valuation model. The Company utilized the "simplified" method to estimate the expected term of the stock options granted as at the time there was limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the
LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company issues new shares.
The Company recorded $12.1 million, $15.1 million and $15.7 million of stock-based compensation costs related to the stock options for the years ended December 31, 2019, 2018 and 2017, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2019, there are no remaining unrecognized compensation costs related to the stock options granted to certain executives.
The following table summarizes the assumptions used for the Black-Scholes valuation model to calculate the stock-based compensation expense for the year ended December 31, 2017. No stock options were granted for the years ended December 31, 2019 and 2018.
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
December 31, 2017
|
|
Risk free rates
|
2.0
|
%
|
|
Dividend yield
|
—
|
|
|
Expected volatility
|
58.9
|
%
|
|
Expected term (in years)
|
6.0
|
|
|
|
|
The weighted average fair value at the date of grant for stock options granted is as follows:
|
|
|
Weighted average per share
|
$
|
8.66
|
|
|
Total options granted
|
744,428
|
|
|
Total weighted average fair value of options granted (in thousands)
|
$
|
6,445
|
|
The following table summarizes the stock option activity from January 1, 2017 through December 31, 2019 and provides information for stock options outstanding at the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average Exercise Price
|
|
Aggregate Intrinsic Value (in thousands)
|
|
Non-vested Stock Options at January 1, 2017
|
4,500,000
|
|
|
$
|
19.00
|
|
|
$
|
4,680
|
|
|
Granted
|
744,428
|
|
|
$
|
15.53
|
|
|
$
|
—
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Vested
|
(1,748,138)
|
|
|
$
|
18.52
|
|
|
$
|
—
|
|
|
Non-vested Stock Options at December 31, 2017
|
3,496,290
|
|
|
$
|
18.50
|
|
|
$
|
—
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Vested
|
(1,748,142)
|
|
|
$
|
18.49
|
|
|
$
|
—
|
|
|
Non-vested Stock Options at December 31, 2018
|
1,748,148
|
|
|
$
|
18.50
|
|
|
$
|
—
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Vested
|
(1,748,148)
|
|
|
$
|
18.50
|
|
|
$
|
—
|
|
|
Non-vested Stock Options at December 31, 2019
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The following table summarizes information about outstanding and exercisable stock options as of December 31, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding and Exercisable Options
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
Weighted-Average
|
|
|
|
Options
|
|
Remaining Contractual Life
|
|
Exercise Price
|
|
Aggregate Intrinsic Value (thousands)
|
|
4,500,000
|
|
|
6.9 years
|
|
$
|
19.00
|
|
|
$
|
—
|
|
|
744,428
|
|
|
7.8 years
|
|
$
|
15.53
|
|
|
$
|
—
|
|
|
5,244,428
|
|
|
7.0 years
|
|
$
|
18.50
|
|
|
$
|
—
|
|
Incentive Restricted Stock Units
Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC ("Employee Incentive"), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units ("Incentive RSUs") to certain employees. Incentive RSUs vested over a three-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vested 25%, 25% and 25% each six months thereafter, over the remaining 18 month service period. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.
The Company recorded $0.8 million, $19.6 million and $17.3 million of stock-based compensation costs related to Incentive RSUs for the years ended December 31, 2019, 2018 and 2017, respectively. These costs were included in the statements of operations within the general and administrative expenses line item. As of December 31, 2019, there are no remaining unrecognized compensation costs related to the Incentive RSUs granted to certain employees.
The following table summarizes the Incentive RSU activity from January 1, 2017 through December 31, 2019 and provides information for Incentive RSUs outstanding at the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Shares
|
|
Fair Value
|
|
Non-vested Incentive RSUs at January 1, 2017
|
2,714,368
|
|
|
$
|
—
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
Forfeited
|
(710,993)
|
|
|
$
|
20.45
|
|
|
Vested
|
(507,200)
|
|
|
$
|
—
|
|
|
Non-vested Incentive RSUs at December 31, 2017
|
1,496,175
|
|
|
$
|
20.45
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
Forfeited
|
(41,400)
|
|
|
$
|
20.45
|
|
|
Vested
|
(978,775)
|
|
|
$
|
20.45
|
|
|
Non-vested Incentive RSUs at December 31, 2018
|
476,000
|
|
|
$
|
20.45
|
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
Vested
|
(476,000)
|
|
|
$
|
20.45
|
|
|
Non-vested Incentive RSUs at December 31, 2019
|
—
|
|
|
$
|
—
|
|
Note 13—Earnings (Loss) Per Share
Basic earnings per share ("EPS") includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the "if-converted" method to determine potential dilutive effects of Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options.
The components of basic and diluted EPS were as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Basic and Diluted Income (Loss) per Share
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(1,367,420)
|
|
|
$
|
121,855
|
|
|
$
|
(44,408)
|
|
|
Less: Noncontrolling interest
|
(19,992)
|
|
|
(7,287)
|
|
|
—
|
|
|
Less: Adjustment to reflect Series A Preferred Stock dividend
|
(12,796)
|
|
|
(10,885)
|
|
|
(10,885)
|
|
|
Less: Adjustment to reflect accretion of Series A Preferred Stock discount
|
(6,640)
|
|
|
(5,984)
|
|
|
(5,394)
|
|
|
Net income (loss) available to common shareholders, basic and diluted
|
$
|
(1,406,848)
|
|
|
$
|
97,699
|
|
|
$
|
(60,687)
|
|
|
Weighted Average Common Shares Outstanding (1) (2) (3)
|
|
|
|
|
|
|
Basic and diluted
|
151,481
|
|
|
174,748
|
|
|
171,910
|
|
|
Net Income (Loss) Allocated to Common Shareholders per Common Share
|
|
|
|
|
|
|
Basic and diluted
|
$
|
(9.29)
|
|
|
$
|
0.56
|
|
|
$
|
(0.35)
|
|
(1)For the year ended December 31, 2019, 2,635,765 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(2)For the year ended December 31, 2018, 3,102,335 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(3)For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
Note 14—Commitments and Contingencies
Leases
The Company has entered into operating leases for certain office facilities, compressors and office equipment. The Company leases two office spaces in Denver, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2028, respectively. The Houston lease expires on January 31, 2022. Rent expense was $3.4 million and $2.3 million for the years ended December 31, 2018 and 2017, respectively. On January 1, 2019, the Company adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 5—Leases for additional information.
Drilling Rigs
As of December 31, 2019, the Company was subject to commitments on two drilling rigs contracted through May 2020 and February 2021. These costs are capitalized within proved oil and gas properties on the consolidated balance sheets and are included as short-term and long-term lease costs in Note 5—Leases. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate remaining amount of approximately $13.3 million as of December 31, 2019, as required under the terms of the contracts.
Maturities of operating lease liabilities, associated with Right-of-Use assets and including imputed interest, as of December 31, 2019, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
2020
|
$
|
19,040
|
|
|
2021
|
5,247
|
|
|
2022
|
2,211
|
|
|
2023
|
2,246
|
|
|
2024
|
2,301
|
|
|
Thereafter
|
8,273
|
|
|
Total lease payments
|
$
|
39,318
|
|
|
Less imputed interest (1)
|
(4,735)
|
|
|
Present value of lease liabilities (2)
|
$
|
34,583
|
|
(1)Calculated using the estimated interest rate for each lease.
(2)Of the total present value of lease liabilities, $17.4 million was recorded in "Accounts payable and accrued liabilities" and $17.2 million was recorded in "Other non-current liabilities" on the consolidated balance sheets.
As of December 31, 2018, minimum future contractual payments for operating leases under the scope of ASC 840 for certain office facilities and drilling rigs are as follows (in thousands):
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
2019
|
$
|
12,713
|
|
|
2020
|
3,371
|
|
|
2021
|
3,385
|
|
|
2022
|
3,360
|
|
|
2023
|
3,411
|
|
|
Thereafter
|
15,719
|
|
|
Total lease payments
|
$
|
41,959
|
|
Delivery Commitments
As of December 31, 2019, the Company’s oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment during the contract term. In May 2019, the Company extended the term of this agreement through October 31, 2020 subject to an evergreen provision thereafter where either party can provide a six month notice of termination beginning November 1, 2020. Due to the contract termination date, the amount of consideration recognized in revenue is reduced. See Note 2- Basis of Presentation and Significant Accounting Policies - Contract Balances. The Company has posted a letter of credit for this agreement in the amount of $40.0 million. The Company may be required to pay a shortfall fee for any volume deficiencies under these commitments. The aggregate remaining amount of estimated payments under these agreements is approximately $679.8 million.
The Company has two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company has a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The Company may be required to pay a shortfall fee for any volume deficiencies under this commitment. The second agreement commenced in July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The Company may be required to pay a shortfall fee for any
volume deficiencies under this commitment. The aggregate remaining amount of estimated payments under these agreements is approximately $120.3 million.
In February 2019, the Company entered into two long-term gas gathering and processing agreements with third-party midstream providers. One of the agreements additionally includes a long-term NGL sales commitment for take-in-kind NGLs from other processing agreements. The first agreement commenced in November 2019 and has a term of twenty years with a minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to be delivered on an average 85,000 Mcf/d in year one, 125,000 Mcf/d in year two, 140,000 Mcf/d in year three, 118,000 Mcf/d in year four, 98,000 Mcf/d in year five, 70,000 Mcf/d in year six and 52,000 Mcf/d in year seven. The aggregate remaining amount of estimated payments under this agreement is approximately $308.4 million. The second agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The second agreement also includes a commitment to sell take-in-kind NGLs of 4,000 Bbl/d in year one and 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month. The Company may be required to pay a shortfall fee for any volume deficiencies under these commitments, calculated based on the applicable gathering and processing fees and/or, with respect to the NGL commitment, the NGL transport cost. Under its current drilling plans, the Company expects to meet these volume commitments.
The summary of these minimum volume commitments as of December 31, 2019, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
Gas (MMcf)
|
|
Total (MBOE)
|
|
2020
|
8,935
|
|
|
|
33,550
|
|
|
14,527
|
|
|
2021
|
10,349
|
|
|
|
46,540
|
|
|
18,106
|
|
|
2022
|
9,128
|
|
|
|
49,758
|
|
|
17,421
|
|
|
2023
|
9,490
|
|
|
|
41,850
|
|
|
16,465
|
|
|
2024
|
9,516
|
|
|
|
34,160
|
|
|
15,209
|
|
|
Thereafter
|
29,308
|
|
|
|
40,260
|
|
|
36,018
|
|
|
Total
|
76,726
|
|
|
246,118
|
|
|
117,746
|
|
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant commenced operations in July 2019. The Company’s share of these commitments will require an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any incremental volume deficiency under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold.
In July 2019, the Company entered into three long-term contracts to supply 125,000 dekatherms of residue gas per day for five years to a transportation company. While our production is expected to satisfy these contracts, the aggregate remaining amount of estimated commitment assuming no production is $32.7 million. The Company has posted a letter of credit for this agreement in the amount of $8.7 million.
The aggregate remaining amount of estimated remaining payments under these agreements is $1,141.2 million.
Elevation Gathering Agreements
In November 2018, Extraction entered into the Elevation Gathering Agreements. Under the agreements, the Company agreed to drill 100 wells in Broomfield and 325 wells in Hawkeye by December 31, 2023 if both facilities are to be built. If Extraction fails to complete the wells by the commitment deadline, then it would be deemed to be in breach of the agreement and Elevation could (at Elevation's discretion) be entitled to make a claim for damages against Extraction and its affiliates. The Elevation Gathering Agreements were amended in April 2019 to provide for, among other amendments, the inclusion of additional gathering facilities in Elevation’s Badger facility. Pursuant to this amendment, if these additional gathering facilities are not completed by April 1, 2020, then within 30 days of such date Extraction would be required to make a payment to Elevation in the amount of 135% of all cost incurred by Elevation as of such date for the development and construction of such
additional gathering facilities. Extraction does not expect to complete these additional gathering facilities by such date. As of December 31, 2019, the costs incurred by Elevation for these additional gathering facilities totaled $33.9 million. Extraction continues to work with Elevation’s financing partner in constructive discussions surrounding this target completion date. In December 2019, the Elevation Gathering Agreements were further amended such to provide Elevation additional connection fees that are consistent with market terms (the "Connect Fees"). In the fourth quarter of 2019, the Company incurred $19.5 million for connect fees pursuant to the Elevation Gathering Agreements and does not expect to incur more than the $23.5 million already paid during 2020 for the year ending December 31, 2020.
General
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations, or cash flows.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met.
Litigation and Legal Items
The Company is involved in various legal proceedings and reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the Company’s best interests. The Company has provided the necessary estimated accruals in the consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, the Company currently believes that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.
Environmental. Due to the nature of the natural gas and oil industry, the Company is exposed to environmental risks. The Company has various policies and procedures to minimize and mitigate the risks from environmental contamination or with respect to environmental compliance issues. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, the Company is not aware of any material environmental claims existing as of December 31, 2019 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws, compliance matters or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in accounts payable and accrued liabilities on the consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.
COGCC Notices of Alleged Violations ("NOAVs"). The Company has received NOAVs from the COGCC for alleged compliance violations that the Company has responded to. At this time, the COGCC has not alleged any specific penalty amounts in these matters. The Company does not believe that any penalties that could result from these NOAVs will have a material effect on our business, financial condition, results of operations or liquidity, but they may exceed $100,000.
Note 15—Related Party Transactions
Office Lease with Related Affiliate
In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the Board of Directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expired on February 28, 2020.
2021 Senior Notes
Several 5% stockholders of the Company were also holders of the 2021 Senior Notes prior to the Tender Offer and the redemption of the 2021 Senior Notes. As of the initial issuance of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million.
2024 Senior Notes
Several 5% stockholders of the Company were also holders of the 2024 Senior Notes. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.
2026 Senior Notes
Several 5% stockholders of the Company were also holders of the 2026 Senior Notes. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.
Increased Ownership in an Unconsolidated Subsidiary
In May 2018, the Company exercised an option to increase its ownership percentage in an unconsolidated subsidiary funded with a $35.3 million promissory note. This note was extinguished with the transfer of units to the unconsolidated subsidiary. The Company also contributed an acreage dedication and minimum volume commitment. See Note 14 — Commitments & Contingencies for a description of the Company's minimum volume commitments.
Note 16—Segment Information
See Note 2 — Basis of Presentation and Significant Accounting Policies - Segment Reporting for a description of the Company's determination of its reportable segments. Prior to the fourth quarter of 2018, the Company had a single operating segment. The Company's Exploration and Production segment revenues are derived from third parties. The Company's Gathering and Facilities segment, also known as Elevation, commenced moving crude oil, natural gas and water through its Badger central gathering facility during the fourth quarter of 2019. The Gathering and Facilities segment had $6.9 million of revenue entirely from the Exploration and Production segment during 2019 and no revenue during 2018. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity.
Financial information of the Company's reportable segments was as follows for the years ended December 31, 2019 and 2018 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
Gathering and Facilities
|
|
Elimination of Intersegment Transactions
|
|
Consolidated Total
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Revenues from third parties
|
$
|
905,374
|
|
|
$
|
1,261
|
|
|
$
|
—
|
|
|
$
|
906,635
|
|
|
Revenues from Extraction
|
—
|
|
|
5,618
|
|
|
(5,618)
|
|
|
—
|
|
|
Total Revenues
|
$
|
905,374
|
|
|
$
|
6,879
|
|
|
$
|
(5,618)
|
|
|
$
|
906,635
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses and Other Income (Expense):
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
$
|
(223,707)
|
|
|
$
|
(2,258)
|
|
|
$
|
5,131
|
|
|
$
|
(220,834)
|
|
|
Depletion, depreciation, amortization and accretion
|
(523,122)
|
|
|
(1,415)
|
|
|
—
|
|
|
(524,537)
|
|
|
Interest income
|
449
|
|
|
1,379
|
|
|
—
|
|
|
1,828
|
|
|
Interest expense
|
(79,232)
|
|
|
—
|
|
|
—
|
|
|
(79,232)
|
|
|
Earnings in unconsolidated subsidiaries
|
—
|
|
|
2,285
|
|
|
—
|
|
|
2,285
|
|
|
Subtotal Operating Expenses and Other Income (Expense):
|
$
|
(825,612)
|
|
|
$
|
(9)
|
|
|
$
|
5,131
|
|
|
$
|
(820,490)
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets
|
$
|
2,554,893
|
|
|
$
|
377,925
|
|
|
$
|
(5,861)
|
|
|
$
|
2,926,957
|
|
|
Capital Expenditures
|
597,677
|
|
|
202,624
|
|
|
—
|
|
|
800,301
|
|
|
Investment in Equity Method Investees
|
—
|
|
|
44,584
|
|
|
—
|
|
|
44,584
|
|
|
Segment EBITDAX
|
607,560
|
|
|
3,653
|
|
|
(487)
|
|
|
610,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
Gathering and Facilities
|
|
Elimination of Intersegment Transactions
|
|
Consolidated Total
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Revenues from third parties
|
$
|
1,060,743
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,060,743
|
|
|
Revenues from Extraction
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Revenues
|
$
|
1,060,743
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,060,743
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses and Other Income (Expense):
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
$
|
(209,169)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(209,169)
|
|
|
Depletion, depreciation, amortization and accretion
|
(435,736)
|
|
|
(39)
|
|
|
—
|
|
|
(435,775)
|
|
|
Interest income
|
461
|
|
|
1,467
|
|
|
—
|
|
|
1,928
|
|
|
Interest expense
|
(123,330)
|
|
|
—
|
|
|
—
|
|
|
(123,330)
|
|
|
Earnings in unconsolidated subsidiaries
|
319
|
|
|
2,544
|
|
|
—
|
|
|
2,863
|
|
|
Subtotal Operating Expenses and Other Income (Expense):
|
$
|
(767,455)
|
|
|
$
|
3,972
|
|
|
$
|
—
|
|
|
$
|
(763,483)
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets
|
$
|
3,896,966
|
|
|
$
|
269,337
|
|
|
$
|
(276)
|
|
|
$
|
4,166,027
|
|
|
Capital Expenditures
|
892,548
|
|
|
108,198
|
|
|
—
|
|
|
1,000,746
|
|
|
Investment in Equity Method Investees
|
—
|
|
|
15,487
|
|
|
—
|
|
|
15,487
|
|
|
Segment EBITDAX
|
658,565
|
|
|
1,187
|
|
|
—
|
|
|
659,752
|
|
The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the years ended December 31, 2019 and 2018 (in thousands). The Company had a single reportable segment during the year ended December 31, 2017, therefore no reconciliation is provided for this period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2019
|
|
For the Year Ended December 31, 2018
|
|
Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes
|
|
|
|
|
Exploration and production segment EBITDAX
|
$
|
607,560
|
|
|
$
|
658,565
|
|
|
Gathering and facilities segment EBITDAX
|
3,653
|
|
|
1,187
|
|
|
Elimination of intersegment transactions segment EBITDAX
|
(487)
|
|
|
|
—
|
|
|
Subtotal of Reportable Segments
|
$
|
610,726
|
|
|
$
|
659,752
|
|
|
Less:
|
|
|
|
|
Depletion, depreciation, amortization and accretion
|
$
|
(524,537)
|
|
|
$
|
(435,775)
|
|
|
Impairment of long lived assets and goodwill
|
(1,337,996)
|
|
|
(70,928)
|
|
|
Exploration and abandonment expenses
|
(88,794)
|
|
|
(31,611)
|
|
|
Gain on sale of property and equipment and assets of unconsolidated subsidiary
|
(421)
|
|
|
136,834
|
|
|
Gain (loss) on commodity derivatives
|
(37,107)
|
|
|
(8,554)
|
|
|
Settlements on commodity derivative instruments
|
5,790
|
|
|
123,518
|
|
|
Premiums paid for derivatives that settled during the period
|
18,929
|
|
|
7,148
|
|
|
Stock-based compensation expense
|
(43,954)
|
|
|
(68,349)
|
|
|
Interest expense
|
(79,232)
|
|
|
|
(123,330)
|
|
|
Income (Loss) Before Income Taxes
|
$
|
(1,476,596)
|
|
|
$
|
188,705
|
|
Note 17—Supplemental Oil and Gas Reserve Information (Unaudited)
Results of Operations for Oil, Natural Gas and NGL Producing Properties
The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before corporate overhead and interest expenses. The Company assumed a statutory rate of 24.7% for the years ended December 31, 2019, 2018 and 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Revenues
|
$
|
905,374
|
|
|
$
|
1,060,743
|
|
|
$
|
604,296
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
Production expenses
|
218,576
|
|
|
209,169
|
|
|
162,673
|
|
|
Exploration and abandonment expenses
|
88,794
|
|
|
31,611
|
|
|
36,256
|
|
|
Depletion, depreciation, amortization and accretion
|
524,537
|
|
|
431,946
|
|
|
311,916
|
|
|
Impairment of proved properties
|
1,337,996
|
|
|
16,166
|
|
|
—
|
|
|
Results of operations before income tax benefit (expense)
|
(1,264,529)
|
|
|
371,851
|
|
|
93,451
|
|
|
Income tax benefit (expense)
|
312,339
|
|
|
(91,847)
|
|
|
(23,082)
|
|
|
Results of Operations
|
$
|
(952,190)
|
|
|
$
|
280,004
|
|
|
$
|
70,369
|
|
Oil, Natural Gas and NGL Reserve Quantities (Unaudited)
The reserves at December 31, 2019, 2018 and 2017 presented below were prepared by the independent engineering firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
The following table sets forth information for the years ended December 31, 2019, 2018 and 2017 with respect to changes in the Company's proved (i.e., proved developed and undeveloped) reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
Natural Gas
|
|
NGL
|
|
MBoe
|
|
|
Mbbls
|
|
MMcf
|
|
Mbbls
|
|
Total
|
|
Balance as of December 31, 2016
|
90,995
|
|
|
507,735
|
|
|
62,448
|
|
|
238,066
|
|
|
Revisions of previous estimates
|
(626)
|
|
|
9,350
|
|
|
1,962
|
|
|
2,894
|
|
|
Purchase of reserves
|
10,761
|
|
|
11,184
|
|
|
1,563
|
|
|
14,188
|
|
|
Extensions, discoveries, and other additions
|
19,738
|
|
|
130,295
|
|
|
15,034
|
|
|
56,488
|
|
|
Sale of reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Production
|
(9,593)
|
|
|
(32,395)
|
|
|
(3,901)
|
|
|
(18,894)
|
|
|
Balance as of December 31, 2017
|
111,275
|
|
|
626,169
|
|
|
77,106
|
|
|
292,742
|
|
|
Revisions of previous estimates
|
6,264
|
|
|
(49,239)
|
|
|
(1,383)
|
|
|
(3,325)
|
|
|
Purchase of reserves
|
6,296
|
|
|
24,668
|
|
|
3,264
|
|
|
13,672
|
|
|
Extensions, discoveries, and other additions
|
32,475
|
|
|
164,424
|
|
|
22,853
|
|
|
82,733
|
|
|
Sale of reserves
|
(5,786)
|
|
|
(15,907)
|
|
|
(1,730)
|
|
|
(10,167)
|
|
|
Production
|
(14,679)
|
|
|
(46,847)
|
|
|
(5,260)
|
|
|
(27,747)
|
|
|
Balance as of December 31, 2018
|
135,845
|
|
|
703,268
|
|
|
94,850
|
|
|
347,908
|
|
|
Revisions of previous estimates
|
(41,255)
|
|
|
(118,365)
|
|
|
(29,554)
|
|
|
(90,537)
|
|
|
Purchase of reserves
|
275
|
|
|
1,526
|
|
|
217
|
|
|
746
|
|
|
Extensions, discoveries, and other additions
|
14,620
|
|
|
72,880
|
|
|
8,425
|
|
|
35,191
|
|
|
Sale of reserves
|
(2,590)
|
|
|
(14,510)
|
|
|
(1,765)
|
|
|
(6,773)
|
|
|
Production
|
(15,436)
|
|
|
(64,710)
|
|
|
(6,164)
|
|
|
(32,386)
|
|
|
Balance as of December 31, 2019
|
91,459
|
|
|
580,089
|
|
|
66,009
|
|
|
254,149
|
|
|
Proved Developed Reserves, included above
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2017
|
37,078
|
|
|
222,236
|
|
|
27,932
|
|
|
102,049
|
|
|
Balance as of December 31, 2018
|
47,075
|
|
|
316,499
|
|
|
39,689
|
|
|
139,514
|
|
|
Balance as of December 31, 2019
|
45,807
|
|
|
350,309
|
|
|
39,001
|
|
|
143,193
|
|
|
Proved Undeveloped Reserves, included above
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2017
|
74,197
|
|
|
403,933
|
|
|
49,174
|
|
|
190,693
|
|
|
Balance as of December 31, 2018
|
88,771
|
|
|
386,769
|
|
|
55,162
|
|
|
208,395
|
|
|
Balance as of December 31, 2019
|
45,652
|
|
|
229,781
|
|
|
27,008
|
|
|
110,957
|
|
•The values for the 2019 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2019. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $55.69 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.58 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2019 was $48.09 per barrel for oil, $1.04 per Mcf for natural gas and $13.87 per barrel for NGL.
•The values for the 2018 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2018. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $65.56 per barrel (West Texas Intermediate price) for crude oil and NGL and $3.10 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2018 was $57.65 per barrel for oil, $1.47 per Mcf for natural gas and $20.45 per barrel for NGL.
•The values for the 2017 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017. The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $51.34 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
basis differentials. The average resulting price used as of December 31, 2017 was $42.89 per barrel for oil, $1.73 per Mcf for natural gas and $20.28 per barrel for NGL.
For the year ended December 31, 2019, the Company had downward revisions of previous estimates of 90,537 MBoe primarily due to revisions of PUD expirations due to the SEC's five year drilling rule caused by the change in business strategy to focus on being cash flow positive rather than maximizing reserves growth. As a result of ongoing drilling and completion activities during 2019, the Company reported extensions, discoveries, and other additions of 35,191 MBoe. Additionally, during 2019 the Company sold reserves of 6,773 MBoe and purchased reserves of 746 MBoe.
For the year ended December 31, 2018, the Company had upward revisions of previous estimates of 3,325 MBoe. As a result of ongoing drilling and completion activities during 2018, the Company reported extensions, discoveries, and other additions of 82,733 MBoe. Additionally, during 2018 the Company sold reserves of 10,167 MBoe and purchased reserves of 13,672 MBoe.
For the year ended December 31, 2017, the Company had downward revisions of previous estimates of 2,894 MBoe. As a result of ongoing drilling and completion activities during 2017, the Company reported extensions, discoveries, and other additions of 56,488 MBoe. Additionally, during 2017 the Company purchased reserves of 14,188 MBoe.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves
The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.
The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent petroleum engineers.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing twelve-month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Future crude oil, natural gas and NGL sales
|
$
|
5,914,900
|
|
|
$
|
10,805,063
|
|
|
$
|
7,422,335
|
|
|
Future production costs
|
(2,166,852)
|
|
|
(3,215,840)
|
|
|
(2,227,370)
|
|
|
Future development costs
|
(798,225)
|
|
|
(1,912,641)
|
|
|
(1,662,859)
|
|
|
Future income tax expense
|
(7,647)
|
|
|
(694,398)
|
|
|
(212,923)
|
|
|
Future net cash flows
|
$
|
2,942,176
|
|
|
$
|
4,982,184
|
|
|
$
|
3,319,183
|
|
|
10% annual discount
|
(1,038,303)
|
|
|
(2,082,201)
|
|
|
(1,440,177)
|
|
|
Standardized measure of discounted future net cash flows(1)
|
$
|
1,903,873
|
|
|
$
|
2,899,983
|
|
|
$
|
1,879,006
|
|
(1)For the years ended December 31, 2019, 2018 and 2017, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets.
The following are the principal sources of change in the standardized measure (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Balance at beginning of period
|
$
|
2,899,983
|
|
|
$
|
1,879,006
|
|
|
$
|
722,996
|
|
|
Sales of crude oil, natural gas and NGL, net
|
(681,667)
|
|
|
(851,574)
|
|
|
(441,623)
|
|
|
Net change in prices and production costs
|
(878,838)
|
|
|
902,762
|
|
|
586,271
|
|
|
Net change in future development costs
|
3,147
|
|
|
(174,112)
|
|
|
3,959
|
|
|
Extensions and discoveries
|
256,147
|
|
|
629,304
|
|
|
330,160
|
|
|
Acquisitions of reserves
|
9,623
|
|
|
88,124
|
|
|
59,745
|
|
|
Sale of reserves
|
(52,710)
|
|
|
(55,042)
|
|
|
—
|
|
|
Revisions of previous quantity estimates
|
(560,397)
|
|
|
132,373
|
|
|
188,421
|
|
|
Previously estimated development costs incurred
|
348,137
|
|
|
306,546
|
|
|
331,550
|
|
|
Net changes in income taxes
|
347,057
|
|
|
(253,044)
|
|
|
(79,181)
|
|
|
Accretion of discount
|
324,981
|
|
|
197,580
|
|
|
74,061
|
|
|
Changes in production timing and other
|
(111,590)
|
|
|
98,060
|
|
|
102,647
|
|
|
Balance at end of period
|
$
|
1,903,873
|
|
|
$
|
2,899,983
|
|
|
$
|
1,879,006
|
|
Note 18—Unaudited Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data for each of the quarters from first quarter 2018 through fourth quarter 2019 (in thousands, except per share data). Historical results are not necessarily indicative of the results to be expected in future periods. This data should be read together with the Company's consolidated financial statements and the related notes included elsewhere in this Annual Report:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Three Months Ended
|
|
|
|
|
|
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
2019
|
|
2019
|
|
2019
|
|
2019
|
|
Total Revenues
|
$
|
221,917
|
|
|
$
|
222,057
|
|
|
$
|
176,942
|
|
|
$
|
285,720
|
|
|
Operating Income(1)
|
52,796
|
|
|
49,647
|
|
|
22,334
|
|
|
36,488
|
|
|
Net Income (Loss)
|
(94,032)
|
|
|
43,444
|
|
|
33,924
|
|
|
(1,350,758)
|
|
|
Basic and Diluted Income (Loss) Per Common Share
|
(0.60)
|
|
|
0.22
|
|
|
0.17
|
|
|
(9.84)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Three Months Ended
|
|
|
|
|
|
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
2018
|
|
2018
|
|
2018
|
|
2018
|
|
Total Revenues
|
$
|
230,215
|
|
|
$
|
260,196
|
|
|
$
|
282,160
|
|
|
$
|
288,172
|
|
|
Operating Income(1)
|
85,443
|
|
|
98,300
|
|
|
121,171
|
|
|
110,885
|
|
|
Net Income (Loss)
|
(51,995)
|
|
|
8,848
|
|
|
65,150
|
|
|
99,852
|
|
|
Basic Income (Loss) Per Common Share
|
(0.32)
|
|
|
0.03
|
|
|
0.33
|
|
|
0.52
|
|
|
Diluted Income (Loss) Per Common Share
|
(0.32)
|
|
|
0.03
|
|
|
0.33
|
|
|
0.51
|
|
(1)Total revenues less lease operating expenses, midstream operating expenses, transportation and gathering expenses, production taxes and depreciation, depletion, amortization and accretion expenses.