NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Accounting policies used by Comstock Resources, Inc. and subsidiaries reflect oil and natural gas industry practices and conform to accounting principles generally accepted in the United States of America.
Basis of Presentation and Principles of Consolidation
Comstock Resources, Inc. and its subsidiaries are engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The Company's operations are primarily focused in Texas, Louisiana and North Dakota. The consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly owned or controlled subsidiaries (collectively, "Comstock" or the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in oil and gas properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements. Net income (loss) and comprehensive income (loss) are the same in all periods presented.
Management of the Company has assessed the Company's financial condition, the current capital markets and its future plans given different scenarios of oil and natural gas prices and believes the Company has adequate liquidity to fund its operations for at least twelve months from the date of issuance of these financial statements, which is the requirement to be considered a going concern under generally accepted accounting principles. Management cannot predict how an extended period of low oil and natural gas prices will affect the Company's future operations and liquidity levels.
On August 14, 2018, Arkoma Drilling, L.P. and Williston Drilling, L.P. (collectively, the "Jones Partnerships") contributed certain oil and gas properties in North Dakota and Montana (the "Bakken Shale Properties") in exchange for 88,571,429 newly issued shares of common stock representing 84% of the Company's outstanding common stock (the "Jones Contribution"). The Jones Partnerships are wholly owned and controlled by Dallas businessman Jerry Jones and his children (collectively, the "Jones Group").
The Company assessed the Bakken Shale Properties to determine whether they meet the definition of a business under US generally accepted accounting principles, determining that they do not meet the definition of a business. As a result, the Jones Contribution is not being accounted for as a business combination. Upon the issuance of the shares of Comstock common stock, the Jones Group obtained control over Comstock through their ownership of the Jones Partnerships. Through the Jones Partnerships, the Jones Group owns a majority of the voting common stock as well as the ability to control the composition of the majority of the board of directors of Comstock. As a result of the change of control that occurred upon the issuance of the common stock, the Jones Group controls Comstock and, thereby, continues to control the Bakken Shale Properties.
Accordingly, the basis of the Bakken Shale Properties recognized by Comstock is the historical basis of the Jones Group. The historical cost basis of the Bakken Shale properties contributed was $397.6 million, which was comprised of $554.3 million of capitalized costs less $156.7 million of accumulated depletion, depreciation and amortization. The change in control of Comstock results in a new basis for Comstock as the Company has elected to apply pushdown accounting pursuant to ASC 805, Business Combinations. The new basis is pushed down to Comstock for financial reporting purposes, resulting in
F-7
Comstock's assets, liabilities and equity accounts being recognized at fair value upon the closing of the Jones
Contribution
.
References to "Successor" or "Successor Company" relate to the financial position and results of operations of the Company subsequent to August 13, 2018. Reference to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company on or prior to August 13, 2018. The Company's consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after August 13, 2018 and dates prior thereto.
The estimated fair value of Comstock's assets and liabilities and the resulting goodwill at the date of the transaction were as follows:
|
|
(In thousands)
|
|
|
|
|
|
|
Fair Value of Comstock's common stock
|
|
$
|
149,357
|
|
|
|
|
|
|
Fair Value of Liabilities Assumed —
|
|
|
|
|
Current Liabilities
|
|
|
180,452
|
|
Long-Term Debt
|
|
|
2,059,560
|
|
Deferred Income Taxes
|
|
|
63,708
|
|
Reserve for Future Abandonment Costs
|
|
|
4,440
|
|
Net Liabilities Assumed
|
|
|
2,308,160
|
|
|
|
|
|
|
Fair Value of Assets Acquired —
|
|
|
|
|
Current Assets
|
|
|
936,026
|
|
Oil and Gas Properties
|
|
|
1,147,749
|
|
Other Property & Equipment
|
|
|
4,440
|
|
Income Taxes Receivable
|
|
|
19,086
|
|
Other Assets
|
|
|
2
|
|
Total Assets
|
|
|
2,107,303
|
|
Goodwill
|
|
$
|
350,214
|
|
The
table above represents the preliminary allocation of fair value related to the assets acquired and the liabilities assumed based on the fair value of Comstock. Certain data necessary to complete the fair value allocation is not yet available or is in the process of being finalized, and includes, but is not limited to, final income tax returns. The Company expects to complete the purchase price allocation during the twelve month period following the closing of the Jones Contribution, during which time the value of the assets and liabilities, including goodwill, may be revised as appropriate.
Goodwill recognized is primarily attributable to the excess of the fair value of Comstock's common stock over the identifiable assets acquired net of liabilities assumed, measured in accordance with generally accepted accounting principles in the United States. The fair value of oil and gas properties, a Level 3 measurement, was determined using discounted cash flow valuation methodology. Key inputs to the valuation included average oil prices of $79.72 per barrel, average natural gas prices of $3.87 per thousand cubic feet and discount rates of 10% - 25%, based on reserve classification.
The combination of the Bakken Shale Properties with Comstock's Haynesville shale properties results in a Company with adequate resources and liquidity to fully exploit its Haynesville/Bossier shale asset base and to continue to expand its opportunity set with future acquisitions and leasing activity in the basin.
Transaction-related costs (i.e., advisory, legal, accounting, valuation, other professional or consulting fees) totaling approximately $2.6 million are not included as a component of consideration transferred but are accounted for as expenses in the Predecessor Periods in which the costs were incurred and the services received. Costs incurred associated with the issuance of common stock have been accounted for as a reduction of additional paid-in capital.
F-8
The closing of the Jones Contribution triggered payment of an aggregate
of $8.1 million including success fees to financial advisors and certain other fees under our licenses for technical data. These costs were contingent on the consummation of the transactions, all of which were interdependent and all of which had to close
in order to meet the legal requirements of the contribution agreement. None of these fees would have been incurred otherwise. The Jones Contribution also caused a change in control, upon which restricted shares granted to employees and directors vested,
and performance share units granted to executive officers vested at the maximum number of shares granted. The Company had previously recognized stock-based compensation expense of $7.2 million related to these restricted shares and performance share unit
s. The Company did not recognize an expense for the remaining $11.9 million of unrecognized stock-based compensation expense.
The change in control also resulted in
an additional
$0.5 million
of other benefits to the Company's officers
.
The Company's acc
ounting policy for any cost triggered by the consummation of the Jones Contribution was to recognize the cost when the Jones Contribution was consummated. Accordingly, unrecognized stock-based compensation expense has not been recorded in the Consolidated
Statement of Operations for the Predecessor period since that statement depicts the results of operations just prior to consummation of the transaction. In addition, since the Successor period reflects the effects of push-down accounting, these costs hav
e also not been recorded as an expense in the Successor period. These costs are being considered in the purchase accounting adjustments in arriving at the fair value of the liabilities assumed since they were incurred only in the event the transactions su
ccessfully closed, and they are not clearly identifiable to operations either prior to or subsequent to the Jones Contribution.
Under the terms of the Jones Contribution, April 1, 2018 was the effective date for allocation of revenues and expenses related to net cash of the Bakken Shale Properties, and Comstock received $40.7 million related to net cash flow from April 1, 2018 to August 13, 2018 from the Jones Partnerships which has been accounted as part of the Jones Contribution.
The financial statements are presented on the basis of the Bakken Shale Properties being contributed to Comstock in exchange for common stock of Comstock. Comstock is a corporation, which is treated as a taxable C corporation and thus is subject to federal and state income taxes. A deferred tax liability of approximately $77.9 million has been recognized related to the tax basis of the Bakken Shale Properties long-lived assets being less than the book basis in those assets. The recording of this deferred tax liability has been treated as an adjustment to additional paid-in capital in these financial statements. The change in control of Comstock results in a new basis for Comstock as the company is applying pushdown accounting pursuant to ASC 805, Business Combinations. The new basis is pushed down to Comstock for financial reporting purposes, resulting in Comstock's assets, liabilities and equity accounts being recognized at fair value upon the closing of the Jones Contribution. A deferred tax liability, net of valuation allowance of $52.4 million has been recognized related to the change in the basis for financial reporting purposes as compared to the tax basis of the historical Comstock assets.
The unaudited pro forma financial information presented below sets forth the Company's historical statements of operations for the periods indicated and gives effect to the Jones Contribution and the Company's debt refinancing transactions as if "push down" accounting had been applied as of January 1, 2017. Such information is presented for comparative purposes to the Consolidated Statements of Operations only and does not purport to represent what the Company's results of operations would actually have been had these transactions occurred on the date indicated or to project its results of operations for any future period or date.
F-9
|
|
|
Pro Forma
Year Ended
December 31,
|
|
|
|
|
2017
|
|
|
2018
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
|
$
|
225,477
|
|
|
$
|
303,220
|
|
Oil sales
|
|
|
|
224,816
|
|
|
|
245,684
|
|
Total oil and gas sales
|
|
|
|
450,293
|
|
|
|
548,904
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
|
23,755
|
|
|
|
29,841
|
|
Gathering and transportation
|
|
|
|
17,538
|
|
|
|
22,352
|
|
Lease operating
|
|
|
|
59,359
|
|
|
|
56,811
|
|
Depreciation, depletion and amortization
|
|
|
|
192,680
|
|
|
|
170,209
|
|
General and administrative
|
|
|
|
26,137
|
|
|
|
27,415
|
|
Impairment of oil and gas properties
|
|
|
|
43,990
|
|
|
|
—
|
|
Loss on sale of oil and gas properties
|
|
|
|
1,060
|
|
|
|
35,283
|
|
Total operating expenses
|
|
|
|
364,519
|
|
|
|
341,911
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
85,774
|
|
|
|
206,993
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
|
16,753
|
|
|
|
11,346
|
|
Other income
|
|
|
|
530
|
|
|
|
850
|
|
Interest expense
|
|
|
|
(111,686
|
)
|
|
|
(109,195
|
)
|
Total other income (expenses)
|
|
|
|
(94,403
|
)
|
|
|
(96,999
|
)
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
|
(8,629
|
)
|
|
|
109,994
|
|
Benefit from (provision for) income taxes
|
|
|
|
23,119
|
|
|
|
(27,543
|
)
|
Net Income
|
|
|
$
|
14,490
|
|
|
$
|
82,451
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share – basic and diluted
|
|
|
$
|
0.14
|
|
|
$
|
0.78
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding –
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
105,148
|
|
|
|
105,453
|
|
Diluted
|
|
|
|
105,610
|
|
|
|
105,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Excludes $2.6 million of transaction costs associated with the Jones Contribution.
|
|
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of 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. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.
Concentration of Credit Risk and Accounts Receivable
Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company's accounts receivable are due from either purchasers of oil and gas or
F-10
participants in oil and gas wells for which the Company serves as the operator. Generally, operators of oil and gas wells have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales a
re generally unsecured. The Company's policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit lo
sses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been provided.
Other Current Assets
Other current assets at December 31, 2017 and 2018 consist of the following:
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
As of December 31, 2017
|
|
|
As of December 31, 2018
|
|
|
|
|
(In thousands)
|
|
Advance payments for drilling costs
|
|
$
|
—
|
|
|
$
|
9,336
|
|
Production tax refunds receivable
|
|
|
1,409
|
|
|
|
1,453
|
|
Pipe and oil field equipment inventory
|
|
|
998
|
|
|
|
912
|
|
Other
|
|
|
338
|
|
|
|
2,128
|
|
|
|
$
|
2,745
|
|
|
$
|
13,829
|
|
Fair Value Measurements
Certain accounts within the Company's consolidated balance sheets are required to be measured at fair value on a recurring basis. These include cash equivalents held in bank accounts and derivative financial instruments in the form of oil and natural gas price swap agreements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:
Level 1 – Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.
Level 2 – Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.
Level 3 – Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.
The Company's cash and cash equivalents valuation is based on Level 1 measurements. The Company's oil and natural gas price derivative financial instruments were not traded on a public exchange, and their value is determined utilizing a discounted cash flow model based on inputs that are readily available in public markets and, accordingly, the valuation of these derivative financial instruments is categorized as a Level 2 measurement. There are no financial assets or liabilities accounted for at fair value as of December 31, 2018 that are a Level 3 measurement.
F-11
As of December 31,
2018
, the Company's other financial instruments, comprised solely of its
long-term
debt, had a carrying value of $
1.3
b
illion and a fair value of $
1.2
b
illion. As of December 31, 201
8
, the Company's fixed rate debt had a carrying value of $
8
17.1
m
illion and a fair value of $
720.0
m
illion. The fair market value of the Company'
s fixed rate debt was based on quoted prices as of December 31, 201
8
, a Level 2 measurement.
The fair value of the floating rate debt outstanding at December 31, 2018 approximated its carrying value, a Level 2 measurement.
Property and Equipment
The Company follows the successful efforts method of accounting for its oil and gas properties. Costs incurred to acquire oil and gas leasehold are capitalized. Acquisition costs for proved oil and gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. Exploration expense includes geological and geophysical expenses and delay rentals related to exploratory oil and gas properties, costs of unsuccessful exploratory drilling and impairments of unproved properties. As of December 31, 2018, the unproved properties primarily relates to future drilling locations that were not included in proved undeveloped reserves. These future drilling locations are located on acreage where the reservoir is known to be productive but have been excluded from proved reserves due to uncertainty on whether the wells would be drilled within the next five years as required by SEC rules in order to be included in proved reserves. The costs of unproved properties are transferred to proved oil and gas properties when they are either drilled or they are reflected in proved undeveloped reserves and amortized on an equivalent unit-of-production basis. Costs associated with unevaluated exploratory acreage are periodically assessed for impairment on a property by property basis, and any impairment in value is included in exploration expense. During 2016, impairment charges of $84.1 million were recognized in exploration expense related to certain exploratory leases that the Company no longer expected to drill. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found commercial proved oil and gas reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.
The Company periodically assesses the need for an impairment of the costs capitalized for its proved oil and gas properties. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its oil and gas properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for oil and natural gas prices, future oil and natural gas production, production costs, capital expenditures, and the total proved and risk-adjusted probable oil and natural gas reserves expected to be recovered. Management's oil and natural gas price outlook is developed based on third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of the oil and gas leases.
F-12
In 2017
,
t
he Company recognized an impairment of $
43.8
million to adjust the carrying valu
e of
Comstock
's South Texas
oil properties
which were classified as held for sale at December 31, 2017.
In 2016, the Company recognized impairments of $27.1 million on certain of its oil and gas properties
.
The Company's estimates of undiscounted future net cash flows attributable to its oil and gas properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable oil and natural gas reserves, results of future drilling activities, future prices for oil and natural gas, and increases or decreases in production and capital costs. As a result of these changes, there may be impairments in the carrying values of our oil and gas properties.
Other property and equipment consists primarily of computer equipment, furniture and fixtures and an airplane which are depreciated over estimated useful lives ranging from three to 31½ years on a straight-line basis.
Goodwill
The Company has goodwill of $350.2 million as of December 31, 2018 that was recorded in connection with the Jones Contribution. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets. The Company is not required to amortize goodwill as a charge to earnings; however, the Company is required to conduct an annual review of goodwill for impairment. The Company performs annual reviews of goodwill.
The Company determines the potential for impairment of its goodwill by initially preparing a qualitative fair value assessment of its business value. In performing this qualitative assessment, the Company examines relevant events and circumstances that could have a negative effect on its business, including macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events.
If the qualitative assessment indicates that it is more likely than not that Comstock's business is impaired, a quantitative analysis would be performed to assess the Company's fair value and to determine the amount of impairment, if any, that requires recognition. When performing a quantitative impairment assessment of goodwill, fair value is determined based on a combination of (i) recent market transactions, where available; and (ii) projected discounted cash flows (an income approach). Under the market approach, fair value would be estimated by a comparison to similar businesses whose securities are actively traded in the public market. This requires Comstock's management to make certain judgments, including the selection of comparable companies, comparable recent company asset transactions, transaction premiums and selected financial metrics. Under the income approach, fair value is based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenues, estimates of future operating, administrative and capital costs adjusted for inflation, projected reserves quantities, the probability of success for future exploration for and development of proved and unproved reserves, discount rates and other variables. Future cash flows are discounted using discount factors applied by Comstock when assessing oil and gas acquisition opportunities and which the Company believes provide a fair market value of its business. Negative revisions of estimated reserves quantities, sustained decreases in crude oil or natural gas prices, increases in future cost estimates, or divestitures could lead to reductions in expected future cash flows that would indicate potential impairment of all or a portion of goodwill in future periods.
If the carrying value of goodwill exceeds the fair value calculated using the quantitative approach, an impairment charge would be recorded for the difference between fair value and carrying value. If oil or natural gas prices decrease, drilling efforts are unsuccessful or the Company’s market capitalization declines, it is reasonably possible that additional impairments would need to be recognized.
F-13
Accrued Expenses
Accrued expenses at December 31, 2017 and 2018 consist of the following:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
As of December 31, 2017
|
|
|
As of December 31, 2018
|
|
|
|
(In thousands)
|
|
Accrued interest payable
|
|
$
|
21,277
|
|
|
$
|
35,461
|
|
Accrued drilling costs
|
|
|
5,874
|
|
|
|
17,920
|
|
Accrued transportation costs
|
|
|
3,269
|
|
|
|
4,632
|
|
Accrued employee compensation
|
|
|
6,449
|
|
|
|
6,045
|
|
Accrued lease operating expenses
|
|
|
68
|
|
|
|
2,130
|
|
Asset retirement obligation – assets held for sale
|
|
|
4,557
|
|
|
|
—
|
|
Other
|
|
|
961
|
|
|
|
1,898
|
|
|
|
$
|
42,455
|
|
|
$
|
68,086
|
|
Reserve for Future Abandonment Costs
The Company's asset retirement obligations relate to future plugging and abandonment costs of its oil and gas properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.
The following table summarizes the changes in the Company's total estimated liability:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
Year Ended
December 31, 2017
|
|
|
For the Period from
January 1, 2018 through
August 13, 2018
|
|
|
For the Period from
August 14, 2018 through
December 31, 2018
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
Reserve for future abandonment costs at beginning of the year
|
|
$
|
15,804
|
|
|
$
|
10,407
|
|
|
$
|
4,683
|
|
New wells placed on production
|
|
|
7
|
|
|
|
17
|
|
|
|
50
|
|
Changes in estimates and timing
|
|
|
(1,260
|
)
|
|
|
—
|
|
|
|
270
|
|
Liabilities settled
|
|
|
(77
|
)
|
|
|
(87
|
)
|
|
|
—
|
|
Assets held for sale
|
|
|
(4,557
|
)
|
|
|
—
|
|
|
|
—
|
|
Asset divestitures
|
|
|
(320
|
)
|
|
|
—
|
|
|
|
—
|
|
Accretion expense
|
|
|
810
|
|
|
|
346
|
|
|
|
133
|
|
Reserve for future abandonment costs at end of the year
|
|
$
|
10,407
|
|
|
$
|
10,683
|
|
|
$
|
5,136
|
|
Stock-based Compensation
The Company has stock-based employee compensation plans under which stock awards, comprised primarily of restricted stock and performance share units, are issued to employees and non-employee directors. The Company follows the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.
Segment Reporting
The Company presently operates in one business segment, the exploration and production of oil and natural gas.
F-14
Derivative Financial Instruments and Hedging Activities
The Company accounts for derivative financial instruments (including derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. The Company estimates fair value based on a discounted cash flow model. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities.
Major Purchasers
In 2016, the Company had four major purchasers of its oil and natural gas production that represented 42%, 17%, 14% and 12% of its total oil and gas sales. In 2017, the Company had four major purchasers of its oil and natural gas production that accounted for 34%, 17%, 16% and 15% of its total oil and gas sales. In the Predecessor Period January 1, 2018 through August 13, 2018 the Company had three major purchasers of its oil and gas production that accounted for 33%, 22% and 20% of its total oil and natural gas sales. During the Successor Period August 14, 2018 through December 31, 2018, the Company had two major purchasers of its oil and natural gas production that accounted for 32% and 18% of its total oil and natural gas sales. The loss of any of these purchasers would not have a material adverse effect on the Company as there is an available market for its oil and natural gas production from other purchasers.
Revenue Recognition and Gas Balancing
On January 1, 2018, the Company adopted Financial Accounting Standards Board ("FASB") Accounting Standards Update ("ASU") 2014-09,
Revenue from Contracts with Customers (Topic 606)
("ASU 2014-09").
Comstock adopted this standard using the modified retrospective method of adoption, and it applied the ASU only to contracts that were not completed as of January 1, 2018. Upon adoption, there were no adjustments to the opening balance of equity.
Comstock produces oil and natural gas and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Payment is reasonably assured upon delivery of production. All sales are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party. Prices for sales of oil and natural gas are generally based upon terms that are common in the oil and gas industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for oil and natural gas routinely fluctuate based on changes in these factors. Each unit of production (barrel of crude oil and thousand cubic feet of natural gas) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.
Comstock has elected to exclude all taxes from the measurement of transaction prices, and its revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling crude oil and natural gas, on behalf of royalty owners and working interest owners. Revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenue received have not been significant. The amount of oil or natural gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2017 or 2018. Sales of oil and natural gas generally occur at or near the wellhead. When sales of oil and gas occur at locations other than the wellhead, the Company accounts for costs incurred to
F-15
transport the production to the delivery point as gathering and transportation expenses. The Company has
recognized accounts receivable of $
87.6
million as of December 31, 2018 from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.
Accounts receivable for oil and gas sales at December
31, 2018 increased from accounts receivable at December 31, 2017 mainly due to our higher production of natural gas and
oil and natural gas
production from the Bakken shale properties that were contributed to the Company in August, 2018.
General and Administrative Expenses
General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the oil and gas properties operated by the Company of $12.4 million, $11.7 million, $8.5 million and $4.5 million in 2016, 2017, for the Predecessor Period from January 1, 2018 through August 13, 2018, and for the Successor Period from August 14, 2018 through December 31, 2018, respectively.
Income Taxes
The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the tax consequences attributable to the future utilization of existing net operating loss and other carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.
Earnings Per Share
Unvested share-based payment awards containing nonforfeitable rights to dividends are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. Performance share units ("PSUs") represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the contingency period. The treasury stock method is used to measure the dilutive effect of PSUs. Unexercised common stock warrants represent the right to convert the warrants into common stock at an exercise price of $0.01 per share. The treasury stock method is used to measure the dilutive effect of unexercised common stock warrants. The shares that would be issuable upon exercise of the conversion rights contained in the Company's convertible debt for each period were based on the if-converted method for computing potentially dilutive shares of common stock that could be issued upon conversion. None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses.
F-16
Basic and diluted earnings per share were determined as follows:
|
|
|
|
|
|
Successor
|
|
|
|
For the Period from August 14, 2018
through December 31, 2018
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per
Share
|
|
|
|
(In thousands, except per share amounts)
|
|
Net income attributable to common stock
|
|
$
|
64,122
|
|
|
|
|
|
|
|
|
|
Income allocable to unvested restricted shares
|
|
|
(248
|
)
|
|
|
|
|
|
|
|
|
Basic income attributable to common stock
|
|
|
63,874
|
|
|
|
105,453
|
|
|
$
|
0.61
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock warrants
|
|
|
—
|
|
|
|
6
|
|
|
|
|
|
Diluted income attributable to common stock
|
|
|
63,874
|
|
|
|
105,459
|
|
|
$
|
0.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Twelve Months Ended
December 31, 2016
|
|
|
Twelve Months Ended
December 31, 2017
|
|
|
For the Period January 1, 2018 through August 13, 2018
|
|
|
|
Loss
|
|
|
Shares
|
|
|
Per Share
|
|
|
Loss
|
|
|
Shares
|
|
|
Per Share
|
|
|
Loss
|
|
|
Shares
|
|
|
Per Share
|
|
|
|
(In thousands, except per share amounts)
|
|
Basic and diluted net loss attributable to common stock
|
|
$
|
(135,134
|
)
|
|
|
11,729
|
|
|
$
|
(11.52
|
)
|
|
$
|
(111,405
|
)
|
|
|
14,644
|
|
|
$
|
(7.61
|
)
|
|
$
|
(92,754
|
)
|
|
|
15,262
|
|
|
$
|
(6.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted per share amounts are the same for the Predecessor periods due to the net loss in those periods.
S
hares of unvested restricted stock are included in common stock outstanding as such shares have a nonforfeitable right to participate in any dividends that might be declared and have the right to vote. Weighted average shares of unvested restricted stock included in common stock outstanding were as follows:
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
2016
|
|
|
2017
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
(In thousands)
|
|
|
|
|
Unvested restricted stock
|
|
|
344
|
|
|
|
612
|
|
|
|
839
|
|
|
|
410
|
|
A
ll stock options, unvested PSUs, warrants exercisable into common stock and contingently issuable shares related to the convertible debt that were anti-dilutive to earnings and excluded from weighted average shares used in the computation of earnings per share were as follows:
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
2016
|
|
|
2017
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average PSUs
|
|
|
136
|
|
|
|
274
|
|
|
|
476
|
|
|
|
328
|
|
Weighted average grant date fair value per unit
|
|
|
$22.17
|
|
|
|
$17.12
|
|
|
|
$13.83
|
|
|
|
$12.93
|
|
Weighted average stock options
|
|
|
11
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average exercise price per share
|
|
|
$166.10
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average warrants for common stock
|
|
|
337
|
|
|
|
463
|
|
|
|
142
|
|
|
|
—
|
|
Weighted average exercise price per share
|
|
|
$0.01
|
|
|
|
$0.01
|
|
|
|
$0.01
|
|
|
|
—
|
|
Weighted average contingently convertible shares
|
|
|
11,574
|
|
|
|
37,046
|
|
|
|
39,819
|
|
|
|
—
|
|
Weighted average conversion price per share
|
|
|
$12.32
|
|
|
|
$12.32
|
|
|
|
$12.32
|
|
|
|
—
|
|
F-17
Supplementary Information With Respect to the Consolidated Statements of Cash Flows
For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Cash payments made for interest and income taxes were as follows:
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
Year Ended
December 31,
|
2016
|
|
|
2017
|
|
|
(In thousands)
|
|
|
|
|
Interest payments
|
|
$
|
105,449
|
|
|
$
|
73,941
|
|
|
$
|
36,187
|
|
|
$
|
8,042
|
|
Income tax payments
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
—
|
|
The Company paid $11.9 million, $38.1 million and $25.0 million of interest in-kind on its convertible notes in 2016, 2017 and the Predecessor Period from January 1, 2018 through August 13, 2018, respectively.
Recent accounting pronouncements
In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04) "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment." ASU 2017-04 eliminates step two of the goodwill impairment test and specifies that goodwill impairment should be measured by comparing the fair value of a reporting unit with its carrying amount. ASU 2017-04 is effective for annual or interim goodwill impairment tests performed in fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company has initially recognized goodwill in its financial statements for the quarter ended September 30, 2018 and it will assess the impact of ASU 2017-04 on its financial statements when it performs its annual impairment assessments following adoption of this standard in 2020.
In February 2016, the FASB issued ASU No. 2016-02, Leases ("ASU 2016-02"). ASU 2016-02 requires lessees to include most leases on their balance sheets, but recognize lease costs in their financial statements in a manner similar to accounting for leases prior to ASC 2016-02. ASU 2016-02 is effective for annual periods ending after December 15, 2018 and interim periods thereafter. The Company is adopting ASC 2016-02 beginning January 1, 2019; Comstock is using the modified retrospective method of adoption for this new standard and is applying several of the available transition practical expedients as part of adoption. The adoption of ASC 2016-02 is not expected to have a significant effect on the Company's results of operations, liquidity or financial position.
(2) Acquisitions and Dispositions of Oil and Gas Properties
In December 2016, the Company sold certain of its natural gas properties located in South Texas realizing net proceeds of $25.8 million. The Company recognized a loss on the sale of these assets in 2016 totaling $13.4 million and an impairment of $20.8 million in the first quarter of 2016 to adjust the carrying value of these assets to their fair value. The Company also sold certain other oil and gas properties during 2016 for total proceeds of $2.1 million. The Company recognized a loss of $1.6 million on these divestitures.
In October 2017, the Company adopted a plan of sale for its Eagle Ford shale oil properties located in South Texas. The Company recognized an impairment of $43.8 million in the fourth quarter of 2017 to adjust the carrying value of these assets to their fair value less costs to sell. The Company determined the fair value based on estimated discounted future net cash flows of the properties appropriately risk
F-18
adjusted based on indication of values received from potential acquirers in a competitive bid process. The asset retirement liability of $4.6 million associated with these assets was reclassified to current liabil
ities as of December 31, 2017.
In
April 2018, Comstock completed the sale of its producing Eagle Ford shale oil and gas properties for $1
0
6.4
million
and retained the
undeveloped acreage
. T
he Company recognized a loss on sale of
these
properties of $32.7
million during the Predecessor Period from January 1, 2018 through August 13, 2018.
Results of operations for the properties that were sold and classified as held for sale in 2016, 2017 and during the Predecessor Period from January 1 through August 13, 2018 were as follows:
|
|
Predecessor
|
|
|
|
Year Ended
December 31,
|
|
|
For the Period from January 1, 2018 through August 13, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
Total oil and gas sales
|
|
$
|
63,303
|
|
|
$
|
48,949
|
|
|
$
|
17,747
|
|
Total operating expenses
(1)
|
|
|
(80,467
|
)
|
|
|
(44,861
|
)
|
|
|
(6,134
|
)
|
Operating income (loss)
|
|
$
|
(17,164
|
)
|
|
$
|
4,088
|
|
|
$
|
11,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes direct operating expenses, depreciation, depletion and amortization and exploration expense. Excludes interest expense, general and administrative expenses and depreciation, depletion and amortization expense subsequent to the date the assets were designated as held for sale.
|
In January 2016, the Company exchanged certain oil and gas properties with another operator in a non-monetary exchange. Under the exchange, the Company received 3,637 net acres in DeSoto Parish, Louisiana, prospective for the Haynesville shale, including four producing wells (3.5 net). The Company exchanged 2,547 net acres in Atascosa County, Texas, including seven producing wells (5.3 net) for the Haynesville shale properties. The Company recognized a gain of $0.7 million on this transaction which was included in the loss on sale of oil and gas properties for the year ended December 31, 2016.
In 2017, the Company entered agreements to jointly develop certain acreage prospective for the Haynesville shale in Louisiana and Texas with USG Properties Haynesville, LLC ("USG"). As of December 31, 2017, USG had acquired approximately 6,300 net acres prospective for Haynesville shale development for the joint development program primarily in Caddo Parish, Louisiana. The Company operates wells drilled on USG's acreage and has the right to acquire a 25% working interest in the first twelve wells drilled on the acreage and 40% for all subsequent wells by reimbursing USG for the attributable acreage costs of the wells being drilled. USG is also participating in a Haynesville shale drilling program on approximately 5,700 acres of Comstock's acreage in Harrison County, Texas. Under the terms of the participation agreements, Comstock will receive $1.1 million for 50% of Comstock's interest for each location for acreage and infrastructure related to each well location, with $400,000 of that amount being paid only if each well meets or exceeds established production targets. Comstock also receives $80,000 for each well drilled as consideration for the Company's services managing the joint development program in addition to customary operating fees for each well drilled.
On September 21, 2018, the Company entered into a joint development venture with an affiliate of USG by contributing its undeveloped Eagle Ford shale acreage. Under the joint development venture, Comstock can participate in drilling wells on the undeveloped acreage and can participate in any in-fill wells or refracs of existing wells on acreage owned by the joint venture partner. Comstock subsequently sold a portion of the undeveloped acreage in the joint venture for proceeds of $13.7 million in September 2018.
F-19
On July 31, 2018, the Company acquired oil and gas properties in North Louisiana and Texas for $41.5 million. These properties included 22,559 acres (12,085 net) and 114 (27.8 net) producing natural gas wells, 47 (14.6 net)
of
which produce from the
Haynesville shale.
On August 14, 2018, as part of the Jones Contribution, the strategic drilling venture previously entered into by the Company and Arkoma Drilling, LP was terminated and Comstock re-acquired working interests in wells drilled under the joint venture for $17.9 million representing the costs paid by Arkoma Drilling, LP.
On December 19, 2018, the Company entered into an agreement to acquire an 88% interest in the Haynesville shale rights covering 6,149 gross acres (5,301 net) in Harrison and Panola counties, Texas. The Company will pay $20.5 million over a four year period by providing a 12% interest in each well drilled by Comstock on the acreage. Comstock has identified 33 (22.7 net) potential drilling locations on this acreage.
(3) Oil and Gas Producing Activities
Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred by the Company for its oil and gas property acquisition, development and exploration activities:
Capitalized Costs
|
|
Predecessor
|
|
|
Successor
|
|
|
|
As of December 31, 2017
|
|
|
As of December 31, 2018
|
|
|
|
(In thousands)
|
|
Proved properties:
|
|
|
|
|
|
|
|
|
Leasehold costs
|
|
$
|
491,507
|
|
|
$
|
1,010,987
|
|
Wells and related equipment and facilities
|
|
|
2,140,243
|
|
|
|
671,177
|
|
Accumulated depreciation depletion and amortization
|
|
|
(2,032,927
|
)
|
|
|
(210,452
|
)
|
|
|
|
598,823
|
|
|
|
1,471,712
|
|
Unproved properties
|
|
|
—
|
|
|
|
191,929
|
|
|
|
$
|
598,823
|
|
|
$
|
1,663,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
|
|
For the Years Ended December 31,
|
2016
|
|
|
2017
|
|
|
(In thousands)
|
|
|
|
|
Proved property acquisitions
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
39,323
|
|
|
$
|
21,013
|
|
Development costs
|
|
|
58,587
|
|
|
|
177,432
|
|
|
|
107,559
|
|
|
|
164,393
|
|
Exploration costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
$
|
58,587
|
|
|
$
|
177,432
|
|
|
$
|
146,882
|
|
|
$
|
185,406
|
|
F-20
(4) Long-term Debt
Long-term debt is comprised of the following:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
As of December 31, 2017
|
|
|
As of December 31, 2018
|
|
|
|
(In thousands)
|
|
10% Senior Secured Toggle Notes due 2020:
|
|
|
|
|
|
|
|
|
Principal
|
|
$
|
697,195
|
|
|
$
|
—
|
|
Discount, net of amortization
|
|
|
(8,901
|
)
|
|
|
—
|
|
7¾% Convertible Second Lien PIK Notes due 2019:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
284,442
|
|
|
|
—
|
|
Accrued interest payable in kind
|
|
|
5,572
|
|
|
|
—
|
|
Discount, net of amortization
|
|
|
(38,748
|
)
|
|
|
—
|
|
9½% Convertible Second Lien PIK Notes due 2020:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
187,062
|
|
|
|
—
|
|
Accrued interest payable in kind
|
|
|
817
|
|
|
|
—
|
|
Discount, net of amortization
|
|
|
(31,844
|
)
|
|
|
—
|
|
10% Senior Notes due 2020:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
2,805
|
|
|
|
—
|
|
7¾% Senior Notes due 2019:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
17,959
|
|
|
|
—
|
|
Premium, net of amortization
|
|
|
65
|
|
|
|
—
|
|
9½% Senior Notes due 2020:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
4,860
|
|
|
|
—
|
|
Discount, net of amortization
|
|
|
(70
|
)
|
|
|
—
|
|
9¾% Senior Notes due 2026:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
—
|
|
|
|
850,000
|
|
Discount, net of amortization
|
|
|
—
|
|
|
|
(32,934
|
)
|
Bank Credit Facility:
|
|
|
|
|
|
|
|
|
Principal
|
|
|
—
|
|
|
|
450,000
|
|
Debt issuance costs, net of amortization
|
|
|
(10,685
|
)
|
|
|
(22,703
|
)
|
|
|
$
|
1,110,529
|
|
|
$
|
1,244,363
|
|
The premium and discount on the senior notes are being amortized over the lives of the senior notes using the effective interest rate method. Issuance costs are amortized over the lives of the senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.
The following table summarizes Comstock's principal amount of debt as of December 31, 2018 by year of maturity:
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
2022
|
|
|
2023
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(In thousands)
|
|
Bank credit facility
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
450,000
|
|
|
$
|
—
|
|
|
$
|
450,000
|
|
9¾% Senior Notes Due 2026
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
850,000
|
|
|
$
|
850,000
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
450,000
|
|
|
$
|
850,000
|
|
|
$
|
1,300,000
|
|
In connection with the Jones Contribution, the Company completed a series of refinancing transactions to retire all of its other then-outstanding senior secured and unsecured notes.
F-21
O
n August 3, 2018
, the Company
issued
$850.0
million of new senior notes for procee
d
s of $
815.9 million
. Interest on the notes is
payable
on February 15 and August
15
at an annual rate of
9¾%
and the notes mature on August 15, 2026.
On August 14, 2018, the Company entered into a new bank credit facility with Bank of Montreal, as administrative agent, and the participating banks which matures on August 14, 2023. The bank credit facility is subject to a borrowing base of $700.0 million which is re-determined on a semi-annual basis and upon the occurrence of certain other events. As of December 31, 2018, there were $450.0 million of borrowings outstanding under the revolving credit facility. Borrowings under the bank credit facility are secured by substantially all of the assets of the Company and its subsidiaries, and bear interest at the Company's option, at either LIBOR plus 2.0% to 3.0% or a base rate plus 1.0% to 2.0%, in each case depending on the utilization of the borrowing base. The Company also pays a commitment fee of 0.375% to 0.5% on the unused borrowing base. The bank credit facility places certain restrictions upon the Company's, and its restricted subsidiaries', ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the new senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0 and a current ratio of at least 1.0 to 1.0. The Company was in compliance with the covenants as of December 31, 2018.
(5) Commitments and Contingencies
Commitments
The Company rents office space and other facilities under noncancelable operating leases. Rent expense for the Predecessor Period from January 1, 2018 through August 13, 2018 and for the Successor Period from August 14, 2018 through December 31, 2018 was $1.0 million and $0.6 million, respectively. Rent expense for the years ended December 31, 2016 and 2017 was
$1.5 million and $1.6 million, respectively.
Minimum future payments under the leases at December 31, 2018 are as follows:
|
|
(In thousands)
|
|
2019
|
|
$
|
1,560
|
|
2020
|
|
|
1,560
|
|
2021
|
|
|
1,560
|
|
2022
|
|
|
—
|
|
2023
|
|
|
—
|
|
|
|
$
|
4,680
|
|
The Company
has
entered into natural gas transportation and treating agreements through July 2019. Maximum commitments under these transportation agreements as of December 31, 2018 totaled $0.7 million. As of December 31, 2018, the Company had contracted for contract drilling services through September 2019 of $17.0 million.
Contingencies
From time to time, the Company is involved in certain litigation that arises in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material effect on the Company's financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at December 31, 2017 or 2018.
F-22
(6) Stockholders' Equity
The authorized capital stock of the Company consists of 155 million shares of common stock, $0.50 par value per share, and 5 million shares of preferred stock, $10.00 par value per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. There were no shares of preferred stock outstanding at December 31, 2017 or 2018.
In 2016 and 2017, holders of the Company's convertible notes converted $2.1 million and $9.9 million of principal amount of the notes into 176,175 and 826,327 shares of common stock, respectively.
The Company issued warrants to acquire 1,917,342 shares of common stock for $0.01 per share in connection with a debt exchange completed in 2016. During 2017 and 2018, warrants were exercised for 1,502,255 and 402,708 shares of common stock, respectively, and 11,955 warrants expired without being exercised on September 7, 2018.
(7) Stock-based Compensation
The Company grants restricted shares of common stock and performance share units to key employees and directors as part of their compensation under the 2009 Long-term Incentive Plan. Future awards of performance share units, restricted stock grants or other equity awards are available under the stockholder approved 2009 Long-term Incentive Plan for 152,908 shares of common stock.
Stock-based compensation expense is included in general and administrative expenses. During 2016, 2017, and for the Predecessor Period from January 1, 2018 through August 13, 2018 the Company had $4.7 million, $5.9 million and $3.9 million, respectively, in stock-based compensation expense. For the Successor Period from August 14, 2018 through December 31, 2018, the Company had $1.0 million in stock-based compensation expense.
Restricted Stock
The fair value of restricted stock grants is amortized over the vesting period, generally one to three years, using the straight-line method. The fair value of each restricted share on the date of grant is equal to the market price of a share of the Company's stock.
A summary of restricted stock activity is presented below:
|
Number of
Restricted
Shares
|
|
|
|
Weighted
Average
Grant Price
|
|
|
|
|
|
|
|
|
|
Predecessor Company:
|
|
|
|
|
|
|
|
Outstanding at January 1, 2018
|
|
619,867
|
|
|
|
$11.14
|
|
Granted
|
|
546,027
|
|
|
|
$8.51
|
|
Shares issued for PSUs earned
|
|
85,987
|
|
|
|
—
|
|
Vested
|
|
(339,032
|
)
|
|
|
$11.01
|
|
Forfeitures
|
|
(8,668
|
)
|
|
|
$9.66
|
|
Outstanding at August 13, 2018
|
|
904,181
|
|
|
|
$8.43
|
|
Vested with the Jones Contribution
|
|
(904,181
|
)
|
|
|
$8.43
|
|
|
|
|
|
|
|
|
|
Successor Company:
|
|
|
|
|
|
|
|
Granted
|
|
422,545
|
|
|
|
$8.70
|
|
Forfeitures
|
|
(8,000
|
)
|
|
|
$8.70
|
|
Outstanding at December 31, 2018
|
|
414,545
|
|
|
|
$8.70
|
|
The per share weighted average fair value of restricted stock grants in 2016 and 2017 was $5.46 and $11.11, respectively. The fair value of restricted stock which vested in 2016 and 2017 was $1.3 million and $1.7 million, respectively. Compensation expense recognized for restricted stock grants was $3.4 million, $3.9 million for the Predecessor years ended December 31, 2016 and 2017, respectively.
F-23
The per share weighted average fair value of restricted stock grants during the Predecessor Period from January 1, 2018 throu
gh August 13, 2018 was $8.51. The fair value of restricted stock which vested during the Predecessor Period from January 1, 2018 through August 13,
2018
was $
2.
7
million
and compensation
expense recognized for restricted stock was $2.3 million
during this
period
.
The change of control that occurred due to the Jones Contribution resulted in the vesting of all then outstanding restricted stock grants
which had a fair value of $
7.8
million.
The per share weighted average fair value of restricted stock grants for the Successor Period from August 14, 2018 through December 31, 2018 was $8.70. No restricted shares vested during the Successor Period from August 14, 2018 through December 31, 2018. Compensation expense recognized for restricted stock was $0.5 million for the Successor Period from August 14, 2018 through December 31, 2018. Total unrecognized compensation cost related to unvested restricted stock grants of $3.2 million as of December 31, 2018 is expected to be recognized over a period of 2.6 years.
Performance Share Units
The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria is met during a performance period. The performance periods consist of one to three years. The performance criteria for the PSUs are based on the Company's annualized total stockholder return ("TSR") for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.
The fair value of PSUs was measured at the grant date using the Geometric Brownian Motion Model ("GBM Model"). Significant assumptions used in this simulation include the Company's expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company's peers. Assumptions regarding volatility included the historical volatility of each company's stock and the implied volatilities of publicly traded stock options.
Significant assumptions used to value PSUs included:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
For the Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk free interest rate
|
|
|
0.9%
|
|
|
|
1.6%
|
|
|
|
2.32%
|
|
|
|
2.70%
|
|
Range of implied volatility:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum
|
|
|
47%
|
|
|
|
37%
|
|
|
|
42%
|
|
|
|
30%
|
|
Maximum
|
|
|
92%
|
|
|
|
134%
|
|
|
|
146%
|
|
|
|
88%
|
|
The fair value of PSUs is amortized over the vesting period of one to three years, using the straight-line method. The final number of shares of common stock issued may vary depending upon the performance multiplier, and can result in the issuance of zero to 829,090 shares of common stock based on the achieved performance ranges from zero to two.
F-24
A summary of PSU activity is presented below:
|
|
Number of
PSUs
|
|
|
|
Weighted
Average
Grant Price
|
|
|
|
|
|
|
|
|
|
Predecessor Company:
|
|
|
|
|
|
|
|
Outstanding at January 1, 2018
|
|
281,800
|
|
|
|
$17.12
|
|
Granted
|
|
360,801
|
|
|
|
$12.52
|
|
Unearned
|
|
(42,278
|
)
|
|
|
$18.07
|
|
PSUs earned
|
|
(85,987
|
)
|
|
|
$17.06
|
|
Outstanding at August 13, 2018
|
|
514,336
|
|
|
|
$13.83
|
|
Vested with the Jones Contribution
|
|
(514,336
|
)
|
|
|
$13.83
|
|
|
|
|
|
|
|
|
|
Successor Company:
|
|
|
|
|
|
|
|
Granted
|
|
335,545
|
|
|
|
$12.93
|
|
Outstanding at December 31, 2018
|
|
335,545
|
|
|
|
$12.93
|
|
In 2016, the Company granted 60,015 PSUs with a grant date fair value of $0.4 million, or $7.00 per unit. In 2017, the Company granted 241,814 PSUs with a grant date fair value of $4.4 million, or $18.17 per unit. Total compensation expense recognized for PSUs was
$1.3 million and $2.0 million for the years ended December 31, 2016 and 2017, respectively.
During the Predecessor Period from January 1, 2018 through August 13, 2018, the Company granted 360,801 PSUs with a grant date fair value of $4.5 million, or $12.52 per unit. Total compensation expense recognized for PSUs for the Predecessor Period from January 1, 2018 through August 13, 2018 was $1.6 million. 85,987 PSUs were earned and converted into restricted stock during the Predecessor Period from January 1, 2018 through August 13, 2018.
The change of control that occurred due to the Jones Contribution resulted in the vesting of all then outstanding performance share units at the maximum amount that could be earned, and a total of 1,028,672 shares of common stock were issued related to the earned PSUs with a fair value of $8.8 million.
During the Successor Period from August 14, 2018 through December 31, 2018, the company granted 335,545 PSUs with a grant date for value of $4.3 million, or $12.93 per unit. As of December 31, 2018, there was $3.8 million of total unrecognized expense related to PSUs, which is being amortized through August, 2021. Total compensation expense recognized for PSUs for the Successor Period from August 14, 2018 through December 31, 2018 was $0.5 million.
(8) Retirement Plan
The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match the employees' contributions to the plan. Matching contributions to the plan were
$758,000, $761,000, $508,000 and $252,000 for the years ended December 31, 2016, 2017, the Predecessor Period from January 1, 2018 through August 13, 2018 and the Successor Period from August 14, 2018 through December 31, 2018, respectively.
F-25
(9) Income Taxes
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. The following is an analysis of the consolidated income tax provision (benefit):
|
|
Predecessor
|
|
|
Successor
|
|
|
|
For the Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current - Federal
|
|
$
|
—
|
|
|
$
|
(19,086
|
)
|
|
$
|
—
|
|
|
$
|
(1,349
|
)
|
- State
|
|
|
64
|
|
|
|
136
|
|
|
|
13
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred - Federal
|
|
|
—
|
|
|
|
—
|
|
|
|
2,412
|
|
|
|
16,406
|
|
- State
|
|
|
7,105
|
|
|
|
1,006
|
|
|
|
(1,360
|
)
|
|
|
3,805
|
|
|
|
$
|
7,169
|
|
|
$
|
(17,944
|
)
|
|
$
|
1,065
|
|
|
$
|
18,944
|
|
In recording deferred income tax assets, the Company considers whether it is more likely than not that its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. The Company will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future periods.
The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January 1, 2018 from 35% to 21%. Among the other significant tax law changes that potentially affect the Company are the elimination of the corporate alternative minimum tax ("AMT"), changes that require operating losses incurred in 2018 and beyond be carried forward indefinitely with no carryback up to 80% of taxable income in a given year, and limitations on the deduction for interest expense incurred in 2018 or later of up to 30% of its adjusted taxable income (defined as taxable income before interest and net operating losses) for the taxable year. For the tax years beginning before January 1, 2022, the adjusted taxable income for these purposes is also adjusted to exclude the impact of depreciation, depletion and amortization. The Tax Cuts and Jobs Act preserved deductibility of intangible drilling costs for federal income tax purposes, which allows the Company to deduct a portion of drilling costs in the year incurred and minimizes current taxes payable in periods of taxable income. At December 31, 2018, the Company has completed its accounting for the tax effects of enactment of the Tax Cuts and Jobs Act. The Company has remeasured certain deferred federal tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recognized related to the remeasurement of its deferred federal tax balance was $140.4 million, which was subject to a valuation allowance. The Tax Cuts and Jobs Act repealed the AMT for tax years beginning on or after January 1, 2018 and provides that existing AMT credit carryforwards can be utilized to offset federal taxes for any taxable year. In addition, 50% of any unused AMT credit carryforwards can be refunded during tax years 2018 through 2020. The Company has $20.4 million of unused AMT credit carryforwards as of December 31, 2018.
F-26
The difference between the customary rate of 35%
for 201
6
and
2017
and
21% for 2018 and the effective tax rate on income (losses) is due to the
following:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
For the Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
Tax benefit at statutory rate
|
|
$
|
(44,788
|
)
|
|
$
|
(45,272
|
)
|
|
$
|
(19,255
|
)
|
|
$
|
17,444
|
|
Tax effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMT credit refundable
|
|
|
—
|
|
|
|
(19,086
|
)
|
|
|
—
|
|
|
|
(1,349
|
)
|
Valuation allowance on deferred tax assets
|
|
|
69,890
|
|
|
|
41,116
|
|
|
|
22,053
|
|
|
|
(903
|
)
|
State income taxes, net of federal benefit
|
|
|
(18,860
|
)
|
|
|
(892
|
)
|
|
|
(3,599
|
)
|
|
|
3,863
|
|
Nondeductible stock-based compensation
|
|
|
73
|
|
|
|
1,408
|
|
|
|
668
|
|
|
|
(120
|
)
|
Net operating loss expirations
|
|
|
—
|
|
|
|
1,548
|
|
|
|
—
|
|
|
|
—
|
|
Other
|
|
|
854
|
|
|
|
3,234
|
|
|
|
1,198
|
|
|
|
9
|
|
Total
|
|
$
|
7,169
|
|
|
$
|
(17,944
|
)
|
|
$
|
1,065
|
|
|
$
|
18,944
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
For the Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
Tax at statutory rate
|
|
|
35.0
|
%
|
|
|
35.0
|
%
|
|
|
21.0
|
%
|
|
|
21.0
|
%
|
Tax effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMT credit refundable
|
|
|
—
|
|
|
|
14.8
|
|
|
|
—
|
|
|
|
(1.6
|
)
|
Valuation allowance on deferred tax assets
|
|
|
(54.6
|
)
|
|
|
(31.8
|
)
|
|
|
(24.1
|
)
|
|
|
(1.1
|
)
|
State taxes, net of federal tax benefit
|
|
|
14.7
|
|
|
|
0.7
|
|
|
|
3.9
|
|
|
|
4.7
|
|
Nondeductible compensation
|
|
|
(0.1
|
)
|
|
|
(1.1
|
)
|
|
|
(0.7
|
)
|
|
|
(0.1
|
)
|
Net operating loss expirations
|
|
|
—
|
|
|
|
(1.2
|
)
|
|
|
—
|
|
|
|
—
|
|
Other
|
|
|
(0.6
|
)
|
|
|
(2.5
|
)
|
|
|
(1.3
|
)
|
|
|
—
|
|
Effective tax rate
|
|
|
(5.6
|
%)
|
|
13.9
|
%
|
|
|
(1.2
|
)%
|
|
|
22.9
|
%
|
F-27
T
he tax effects of
significant temporary differences representing the net deferred tax liability at December 31, 201
7
and 201
8
were as follows:
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
2017
|
|
|
2018
|
|
|
|
(In thousands)
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
$
|
3,489
|
|
|
$
|
2,329
|
|
Net operating loss carryforwards
|
|
|
289,803
|
|
|
|
65,317
|
|
Alternative minimum tax carryforward
|
|
|
1,349
|
|
|
|
—
|
|
Interest expense limitation
|
|
|
—
|
|
|
|
45,265
|
|
Gain on debt exchange and
original issue discount
|
|
|
4,336
|
|
|
|
42
|
|
Other
|
|
|
3,782
|
|
|
|
3,711
|
|
|
|
|
302,759
|
|
|
|
116,664
|
|
Valuation allowance on deferred tax assets
|
|
|
(298,539
|
)
|
|
|
(18,390
|
)
|
Deferred tax assets
|
|
|
4,220
|
|
|
|
98,274
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(11,878
|
)
|
|
|
(252,668
|
)
|
Unrealized hedging income
|
|
|
(277
|
)
|
|
|
(3,399
|
)
|
Other
|
|
|
(2,331
|
)
|
|
|
(4,124
|
)
|
Deferred tax liabilities
|
|
|
(14,486
|
)
|
|
|
(260,191
|
)
|
Net deferred tax liability
|
|
$
|
(10,266
|
)
|
|
$
|
(161,917
|
)
|
At December 31, 2018, Comstock had the following carryforwards available to reduce future income taxes:
Types of Carryforward
|
|
|
Years of
Expiration
Carryforward
|
|
Amount
|
|
|
|
|
|
|
(In thousands)
|
|
Net operating loss – U.S. federal
|
|
|
2019-2037
|
|
$
|
930,835
|
|
Net operating loss – U.S. federal
|
|
|
Unlimited
|
|
$
|
132,754
|
|
Net operating loss – state taxes
|
|
|
2020-2037
|
|
$
|
1,531,788
|
|
Interest expense – U.S. Federal
|
|
|
Unlimited
|
|
$
|
215,549
|
|
The shares of common stock issued as a result of the Jones Contribution triggered an ownership change under Section 382 of the Internal Revenue Code. As a result, the Company's ability to use net operating losses ("NOLs") generated before the change in control to reduce taxable income is generally limited to an annual amount based on the fair market value of its stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate. The Company's NOLs are estimated to be limited to $3.3 million a year as a result of this limitation. In addition to this limitation, IRC Section 382 provides that a corporation with a net unrealized built-in gain immediately before an ownership change may increase its limitation by the amount of built-in gain recognized during a recognition period, which is generally the five-year period immediately following an ownership change. Based on the fair market value of the Company's common stock immediately prior to the ownership change, Comstock believes that it has a net unrealized built-in gain which will increase the Section 382 limitation during the five-year recognition period.
NOLs that exceed the Section 382 limitation in any year continue to be allowed as carry forwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. NOLs incurred prior to 2018 generally have a 20-year life until they expire.
F-28
NOLs generated in 2018 and after would be carried forward indefinitely. Comstock's use of new NOLs arising after the date of an ownershi
p change would not be affected by the 382 limitation. If the Company does not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry
-
forward periods, then it will lose the ability to apply those NOLs as offsets to future taxable income.
The Company estimates that $843.0 million of the
U.S.
federal
NOL
carryforward
s
and $1.3 billion of the estimated state
NOL
carryforward
s
will expire u
nused.
The Company's federal income tax returns for the years subsequent to December 31, 2014 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2012. The Company currently believes that its significant filing positions are highly certain and that all of its other significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.
(10) Derivative Financial Instruments and Hedging Activities
Comstock periodically uses swaps, floors and collars to hedge oil and natural gas prices in order to manage oil and natural gas price risk. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.
All of the Company's derivative financial instruments are used for risk management purposes and by policy none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative financial instruments involve payment or receipt of premiums.
The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity and counterparty.
All of Comstock's natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index and all of its oil derivative financial instruments are tied to the WTI-NYMEX index price.
F-29
The Company had the following outstanding derivative financial instruments for natural gas price risk management at December 31, 2018:
|
|
Future Production Period:
Year Ended December 31, 2019
|
|
Natural Gas Swap contracts:
|
|
|
|
|
Volume (MMbtu)
|
|
|
8,700,000
|
|
Average Price per MMbtu
|
|
|
$3.84
|
|
Natural Gas Collar contracts:
|
|
|
|
|
Volume (MMbtu)
|
|
|
34,104,500
|
|
Price per MMbtu:
|
|
|
|
|
Average Ceiling
|
|
|
$3.45
|
|
Average Floor
|
|
|
$2.44
|
|
Oil Collar contracts:
|
|
|
|
|
Volume (Barrels)
|
|
|
1,163,100
|
|
Price per Barrel:
|
|
|
|
|
Average Ceiling
|
|
|
$74.56
|
|
Average Floor
|
|
|
$52.35
|
|
Subsequent to December 31, 2018, the Company has added 18,150,000 MMBtu of additional natural gas collar agreements at an average contract ceiling price of $3.70 per MMBtu and an average contract floor price of $2.51 per MMBtu. These contracts begin in February 2019 and expire in March 2020. Since January 1, 2019 the Company has also added 426,000 barrels of additional oil collar agreements at an average contract ceiling price of $65.79 per barrel and an average contract floor price of $44.63 per barrel. These contracts begin in February 2019 and expire in March 2020. None of the derivative contracts were designated as cash flow hedges. The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses).
None of the Company's derivative contracts were designated as cash flow hedges. The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type, including the classification between assets and liabilities, consists of the following:
Type
|
|
Consolidated
Balance Sheet
Location
|
|
|
Fair
Value
|
|
|
Gross Amounts
Offset in the
Consolidated
Balance Sheet
|
|
|
Net Fair Value
Presented in the
Consolidated
Balance Sheet
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Fair Value of Derivative Instruments as of December 31, 2017
|
|
|
|
|
|
|
|
|
|
Asset Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price derivatives
|
|
Derivative Financial Instruments – current
|
|
|
$
|
$1,318
|
|
|
$
|
—
|
|
|
$
|
1,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor Fair Value of Derivative Instruments as of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price derivatives
|
|
Derivative Financial Instruments – current
|
|
|
$
|
7,264
|
|
|
$
|
(1,168
|
)
|
|
$
|
6,096
|
|
|
Oil price derivatives
|
|
Derivative Financial Instruments – current
|
|
|
$
|
9,305
|
|
|
$
|
—
|
|
|
$
|
9,305
|
|
|
Liability Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price derivatives
|
|
Derivative Financial Instruments – current
|
|
|
$
|
1,168
|
|
|
$
|
(1,168
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-30
The Company recognized cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses). Gains and losses related to the change in the fair value of the Company's derivative contracts recognized in the consolidated statement of operations were as follows:
|
|
Predecessor
|
|
|
Successor
|
|
Location of Gain/(Loss)
Recognized in Earnings on
Derivatives
|
|
Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
Gain (loss) from derivative
financial instruments
|
|
$
|
(5,356
|
)
|
|
$
|
16,753
|
|
|
$
|
881
|
|
|
$
|
10,465
|
|
(11) Supplementary Quarterly Financial Data (Unaudited)
|
|
2017
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(In thousands, except per share data)
|
|
Total oil and gas sales
|
|
$
|
53,801
|
|
|
$
|
61,471
|
|
|
$
|
66,811
|
|
|
$
|
73,248
|
|
Operating loss
|
|
$
|
2,381
|
|
|
$
|
10,470
|
|
|
$
|
11,190
|
|
|
$
|
(24,224
|
)
|
Net income (loss)
|
|
$
|
(22,931
|
)
|
|
$
|
(21,442
|
)
|
|
$
|
(24,736
|
)
|
|
$
|
(42,296
|
)
|
Income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(1.61
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
(1.67
|
)
|
|
$
|
(2.86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
First
|
|
|
Second
|
|
|
July 1 through August 13
|
|
|
August 14 through September 30
|
|
|
Fourth
|
|
|
|
(In thousands, except per share data)
|
|
Total oil and gas sales
|
|
$
|
72,593
|
|
|
$
|
61,449
|
|
|
$
|
32,588
|
|
|
$
|
70,123
|
|
|
$
|
153,498
|
|
Operating income (loss)
|
|
$
|
(5,122
|
)
|
|
$
|
7,716
|
|
|
$
|
8,228
|
|
|
$
|
34,581
|
|
|
$
|
81,450
|
|
Net loss
|
|
$
|
(41,886
|
)
|
|
$
|
(34,003
|
)
|
|
$
|
(16,865
|
)
|
|
$
|
13,823
|
|
|
$
|
50,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(2.78
|
)
|
|
$
|
(2.23
|
)
|
|
$
|
(1.09
|
)
|
|
$
|
0.13
|
|
|
$
|
0.48
|
|
Basic and diluted per share amounts are the same for each of the quarters where a net loss was reported.
Results of operations include the following non-routine items of income (expense), which are presented before the effect of income taxes:
|
|
2017
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(In thousands)
|
|
Gain (loss) on sale of oil and gas properties
|
|
$
|
(24
|
)
|
|
$
|
—
|
|
|
$
|
(1,036
|
)
|
|
$
|
—
|
|
Impairments of proved oil and gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(43,990
|
)
|
F-31
|
|
2018
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
|
First
|
|
|
Second
|
|
|
July 1 through August 13
|
|
|
August 14 through September 30
|
|
|
Fourth
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Gain (loss) on sale of oil and gas properties
|
|
$
|
(28,600
|
)
|
|
$
|
(6,838
|
)
|
|
|
—
|
|
|
$
|
98
|
|
|
$
|
57
|
|
(12) Oil and Gas Reserves Information (Unaudited)
Set forth below is a summary of the changes in Comstock's net quantities of oil and natural gas reserves:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2017
|
|
|
For the Period from January 1, 2018 through August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
|
Oil
(MBbls)
|
|
|
Natural
Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Natural
Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Natural
Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Natural
Gas
(MMcf)
|
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
9,229
|
|
|
|
569,596
|
|
|
|
7,277
|
|
|
|
872,468
|
|
|
|
7,552
|
|
|
|
1,116,956
|
|
|
|
28,994
|
|
1
|
|
2,246,501
|
|
1
|
Revisions of previous estimates
|
|
|
(406
|
)
|
|
|
130,416
|
|
|
|
1,232
|
|
|
|
33,721
|
|
|
|
4
|
|
|
|
17,778
|
|
|
|
5
|
|
|
|
23,949
|
|
|
Extensions and discoveries
|
|
|
64
|
|
|
|
285,076
|
|
|
|
1
|
|
|
|
291,881
|
|
|
|
5,651
|
|
|
|
950,032
|
|
|
|
—
|
|
|
|
30,126
|
|
|
Acquisitions of minerals in place
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
220,088
|
|
|
|
—
|
|
|
|
33,612
|
|
|
Sales of minerals in place
|
|
|
(222
|
)
|
|
|
(58,942
|
)
|
|
|
(7
|
)
|
|
|
(7,593
|
)
|
|
|
(6,870
|
)
|
|
|
(54,341
|
)
|
|
|
(4,002
|
)
|
|
|
(6,399
|
)
|
|
Production
|
|
|
(1,388
|
)
|
|
|
(53,678
|
)
|
|
|
(951
|
)
|
|
|
(73,521
|
)
|
|
|
(287
|
)
|
|
|
(55,240
|
)
|
|
|
(1,385
|
)
|
|
|
(45,031
|
)
|
|
End of period
|
|
|
7,277
|
|
|
|
872,468
|
|
|
|
7,552
|
|
|
|
1,116,956
|
|
|
|
6,050
|
|
|
|
2,195,273
|
|
|
|
23,612
|
|
|
|
2,282,758
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
9,229
|
|
|
|
311,130
|
|
|
|
7,277
|
|
|
|
321,527
|
|
|
|
7,552
|
|
|
|
436,114
|
|
|
|
22,845
|
|
1
|
|
550,198
|
|
1
|
End of period
|
|
|
7,277
|
|
|
|
321,527
|
|
|
|
7,552
|
|
|
|
436,114
|
|
|
|
403
|
|
|
|
500,031
|
|
|
|
21,466
|
|
|
|
583,107
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
—
|
|
|
|
258,466
|
|
|
|
—
|
|
|
|
550,941
|
|
|
|
—
|
|
|
|
680,842
|
|
|
|
6,149
|
|
1
|
|
1,696,303
|
|
1
|
End of period
|
|
|
—
|
|
|
|
550,941
|
|
|
|
—
|
|
|
|
680,842
|
|
|
|
5,647
|
|
|
|
1,695,242
|
|
|
|
2,146
|
|
|
|
1,699,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves associated with Assets
Held for Sale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
8,701
|
|
|
|
9,119
|
|
|
|
6,950
|
|
|
|
9,915
|
|
|
|
7,116
|
|
|
|
10,484
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
6,950
|
|
|
|
9,915
|
|
|
|
7,116
|
|
|
|
10,484
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
8,701
|
|
|
|
9,119
|
|
|
|
6,950
|
|
|
|
9,915
|
|
|
|
7,116
|
|
|
|
10,484
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
6,950
|
|
|
|
9,915
|
|
|
|
7,116
|
|
|
|
10,484
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The beginning proved reserves balance represents the contributed Bakken shale properties and the reserves of the Predecessor on a combined basis.
|
The significant upward revisions to previous estimates in Predecessor Year 2016 were primarily performance-related and were attributable to the Company's well performance in the Haynesville shale as well as the expansion of the Company's future drilling plans.
F-32
The follow
ing table sets forth the standardized measure of discounted future net cash flows relating to proved reserves
:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
As of
December 31,
2017
|
|
|
As of
August 13,
2018
|
|
|
As of
December 31, 2018
|
|
|
|
(In thousands)
|
|
|
|
|
Cash Flows Relating to Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Cash Flows
|
|
$
|
3,588,764
|
|
|
$
|
6,384,203
|
|
|
$
|
8,054,092
|
|
Future Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(986,398
|
)
|
|
|
(1,804,559
|
)
|
|
|
(2,160,912
|
)
|
Development and Abandonment
|
|
|
(672,559
|
)
|
|
|
(1,945,141
|
)
|
|
|
(1,800,335
|
)
|
Future Income Taxes
|
|
|
5,239
|
|
|
|
(199,589
|
)
|
|
|
(622,241
|
)
|
Future Net Cash Flows
|
|
|
1,935,046
|
|
|
|
2,434,914
|
|
|
|
3,470,604
|
|
10% Discount Factor
|
|
|
(1,053,502
|
)
|
|
|
(1,556,927
|
)
|
|
|
(1,996,764
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
881,544
|
|
|
$
|
877,987
|
|
|
$
|
1,473,840
|
|
Standardized Measure of Discounted Future Net Cash Flows Related to Assets Held for Sale
|
|
$
|
109,134
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
|
Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Standardized Measure, Beginning of Year
|
|
$
|
372,139
|
|
|
$
|
429,275
|
|
|
$
|
881,544
|
|
|
$
|
1,317,383
|
|
1
|
Net change in sales price, net of production costs
|
|
|
(45,379
|
)
|
|
|
326,662
|
|
|
|
(61,662
|
)
|
|
|
223,731
|
|
|
Development costs incurred during the year which were previously estimated
|
|
|
45,648
|
|
|
|
119,864
|
|
|
|
86,086
|
|
|
|
112,073
|
|
|
Revisions of quantity estimates
|
|
|
113,583
|
|
|
|
57,042
|
|
|
|
19,815
|
|
|
|
27,090
|
|
|
Accretion of discount
|
|
|
37,251
|
|
|
|
43,130
|
|
|
|
53,413
|
|
|
|
55,692
|
|
|
Changes in future development and abandonment costs
|
|
|
5,315
|
|
|
|
(62,509
|
)
|
|
|
(27,489
|
)
|
|
|
23,139
|
|
|
Changes in timing and other
|
|
|
(38,071
|
)
|
|
|
(15,565
|
)
|
|
|
(17,723
|
)
|
|
|
9,434
|
|
|
Extensions and discoveries
|
|
|
70,149
|
|
|
|
167,135
|
|
|
|
167,986
|
|
|
|
15,263
|
|
|
Acquisitions of minerals in place
|
|
|
—
|
|
|
|
—
|
|
|
|
72,738
|
|
|
|
54,143
|
|
|
Sales of minerals in place
|
|
|
(22,449
|
)
|
|
|
(6,027
|
)
|
|
|
(124,083
|
)
|
|
|
(42,870
|
)
|
|
Sales, net of production costs
|
|
|
(107,253
|
)
|
|
|
(194,562
|
)
|
|
|
(129,991
|
)
|
|
|
(181,218
|
)
|
|
Net changes in income taxes
|
|
|
(1,658
|
)
|
|
|
17,099
|
|
|
|
(42,647
|
)
|
|
|
(140,020
|
)
|
|
Standardized Measure, End of Year
|
|
$
|
429,275
|
|
|
$
|
881,544
|
|
|
$
|
877,987
|
|
|
$
|
1,473,840
|
|
|
(1)
|
The beginning Standardized Measure represents the contributed Bakken shale properties and the reserves of the Predecessor on a combined basis.
|
The standardized measure of discounted future net cash flows was determined based on the simple average of the first of month market prices for oil and natural gas for each year. Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent prices received at the Company's sales point. These prices have been adjusted from posted or index prices for both location and quality differences.
F-33
Prices used in determining oil and natural g
as reserves quantities and cash flows are as follows:
|
|
Predecessor
|
|
|
Successor
|
|
|
|
Years Ended December 31,
|
|
|
For the Period from January 1, 2018 through
August 13, 2018
|
|
|
For the Period from August 14, 2018 through December 31, 2018
|
|
|
|
2016
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil: $/ barrel
|
|
$
|
37.62
|
|
|
$
|
48.71
|
|
|
$
|
62.29
|
|
|
$
|
61.21
|
|
Natural Gas: $/Mcf
|
|
$
|
2.29
|
|
|
$
|
2.88
|
|
|
$
|
2.74
|
|
|
$
|
2.90
|
|
The proved oil and gas reserves utilized in the preparation of the financial statements were estimated by Lee Keeling and Associates, independent petroleum consultants, in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company's reserves are located onshore in the continental United States of America.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
F-34