Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."
Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. Our assets are concentrated in the Haynesville and Bossier shale located in North Louisiana and East Texas, a premier natural gas basin with superior economics due to geographic proximity to Gulf Coast natural gas markets. Approximately 95% of our December 31, 2020 proved reserves are located in the Haynesville and Bossier shale region. We own interests in 2,864 producing oil and natural gas wells (1,453.7 net) and we operate 1,480 of these wells. We intend to maintain an operating plan in 2021 targeting debt reduction and generation of free cash flow.
We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.
We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines or terminals. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production to long-haul gas pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.
Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.
Like all oil and natural gas exploration and production companies, we face the challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $19.3 million of December 31, 2020.
Prices for oil and natural gas have been highly volatile in recent years, and we experienced a period of low prices in 2020 primarily due to an oversupply of oil and natural gas. We expect our oil production to continue to
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decline as we have limited future plans to participate in the drilling of new oil wells. We expect our natural gas production to increase, assuming we maintain a sufficient development program to offset expected production declines from our producing wells. The level of our drilling activity is dependent on natural gas prices. If we are unable to offset production declines resulting from the new wells we plan to drill in 2021 and future periods, our production volumes and cash flows from our operating activities may not be sufficient to fund our capital expenditures, and thus, we may need to either curtail drilling activity or seek additional borrowings, which would result in an increase in our interest expense in 2021 and future periods. We may need to recognize impairments if oil and natural gas prices decline, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value.
Jones Contribution
On August 14, 2018, the Jones Partnerships contributed certain oil and gas properties in North Dakota and Montana in exchange for 88,571,429 newly issued shares of common stock representing 84% of our then 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"). References to "Successor" or "Successor Company" relate to the operations of the Company subsequent to August 13, 2018. References to "Predecessor" or "Predecessor Company" relate to the operations of the Company on or prior to August 13, 2018.
Covey Park Acquisition
On July 16, 2019, we acquired Covey Park Energy LLC ("Covey Park") for total consideration of $700.0 million of cash, the issuance of Series A Convertible Preferred Stock with a redemption value of $210.0 million, and the issuance of 28,833,000 shares of common stock (the "Covey Park Acquisition"). Covey Park's operations were focused primarily in the Haynesville/Bossier shale in North Louisiana and East Texas. In addition to the consideration paid, we assumed $625.0 million of Covey Park's 7.5% senior notes, repaid $380.0 million of Covey Park's then outstanding borrowings under its bank credit facility and redeemed all of Covey Park's preferred equity for $153.4 million. Based on the fair value of the preferred stock issued and the closing price of our common stock of $5.82 per share on July 16, 2019, the transaction was valued at approximately $2.2 billion. On May 20, 2020, we redeemed all of the outstanding shares of the Series A Convertible Preferred Stock for an aggregate redemption price of $210.0 million plus accrued and unpaid dividends of approximately $2.9 million.
Funding for the $700.0 million of cash consideration was provided by the sale of 50 million newly issued shares of our common stock for $300.0 million and 175,000 shares of newly issued Series B Convertible Preferred Stock for $175.0 million to our majority stockholder and by borrowings under our bank credit facility and cash on hand. We incurred $41.0 million of advisory and legal fees and other acquisition-related costs in connection with the Covey Park Acquisition. These costs are included in transaction costs in our consolidated statements of operations.
The acquisition included approximately 249,000 net acres and 2.9 Tcfe of proved reserves. The acquisition added approximately 710 MMcfe of daily average production, at the date of the acquisition, and over 1,200 net future drilling locations. The transaction was accounted for as a business combination, using the acquisition method.
As of December 31, 2020, our majority stockholder owned approximately 60% of our outstanding common stock and the former owners of Covey Park owned approximately 8% of our common stock. The Jones Group also holds our Series B Convertible Preferred Stock that is convertible into 43,750,000 shares of our common stock.
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Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Our operating data for the year ended December 31, 2019 and 2020 are summarized below:
Year Ended December 31,
2019 2020
Oil and Gas Sales (in thousands):
Natural gas sales $635,795 $809,399
Oil sales 132,894 48,796
Total oil and gas sales $768,689 $858,195
Net Production Data:
Natural gas sales (MMcf) 292,834 450,836
Oil sales (MBbls) 2,685 1,508
Total oil and gas (MMcfe) 308,944 459,883
Average Sales Price:
Natural gas sales $2.17 $1.80
Oil sales $49.49 $32.36
Total oil and gas sales $2.49 $1.87
Expenses ($ per Mcfe):
Production and ad valorem taxes $0.11 $0.08
Gathering and transportation $0.23 $0.23
Lease operating $0.27 $0.22
Depreciation, depletion and amortization $0.90 $0.91
Oil and gas sales. Oil and gas sales of $858.2 million in 2020 increased $89.5 million or 12% over oil and gas sales in 2019 of $768.7 million. The increase is due to a 49% increase in production volumes that was partially offset by lower realized oil and natural gas prices in 2020. Our 2020 natural gas production was 450.8 billion cubic feet ("Bcf") (1.2 Bcf per day), which was sold at an average price of $1.80 per Mcf as compared to 292.8 Bcf (0.8 Bcf per day) sold at an average price of $2.17 in 2019. Our 2020 oil production was 1.5 MMBbls (4,120 Bbls per day), which was sold at an average price of $32.36 per Bbl as compared to 2.7 MMBbls (7,356 Bbls per day) sold at an average price of $49.49 per Bbl in 2019.
We utilize natural gas and oil price derivative financial instruments to manage our exposure to natural gas and oil prices and protect returns on investment from our drilling activities. The following table presents our natural gas and oil prices before and after the effect of cash settlements of our derivative financial instruments:
Year Ended December 31,
2019 2020
Average Realized Natural Gas Price:
Natural gas, per Mcf $ 2.17 $ 1.80
Cash settlements on derivative financial instruments, per Mcf 0.18 0.27
Price per Mcf, including cash settlements on derivative financial instruments $ 2.35 $ 2.07
Average Realized Oil Price:
Crude oil per Barrel $ 49.49 $ 32.36
Cash settlements on derivative financial instruments, per Barrel 0.15 8.52
Price per Barrel, including cash settlements on derivative financial instruments $ 49.64 $ 40.88
Cash settlements for oil and natural gas derivative financial instruments totaled $52.7 million and $134.9 million for 2019 and 2020, respectively.
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Production and ad valorem taxes. Our production and ad valorem taxes increased $1.3 million (4%) to $37.0 million in 2020 from $35.7 million in 2019. This increase is primarily related to the $89.5 million increase in oil and gas sales.
Gathering and transportation. Gathering and transportation costs increased $35.3 million or 49% to $106.6 million in 2020 as compared to $71.3 million in 2019. This increase was due primarily to the increase in our natural gas production resulting from our drilling activities and the Covey Park Acquisition completed in 2019.
Lease operating expenses. Our lease operating expenses of $102.5 million in 2020 was $21.7 million or 27% higher than the lease operating expenses in 2019 of $80.8 million. Our lease operating expense of $0.22 per Mcfe produced for 2020 was 0.05 per Mcfe lower than the lease operating expense of $0.27 per Mcfe in 2019. The lower average per unit cost is related to the growth in our lower cost natural gas production where much of the operating costs are fixed in nature.
Depreciation, depletion and amortization expense ("DD&A"). DD&A increased $140.6 million (51%) to $417.1 million in 2020 from $276.5 million in 2019 due to the 49% increase in production. Our DD&A per equivalent Mcf produced was $0.91 per Mcfe in 2020, which was comparable to the $0.90 per Mcfe rate for 2019.
General and administrative expenses. General and administrative expense, which is reported net of overhead reimbursements, increased to $32.0 million in 2020 from $29.2 million in 2019 due primarily to higher stock-based compensation and higher personnel costs. Stock-based compensation was $4.0 million and $6.5 million in 2019 and 2020, respectively.
Derivative financial instruments. We use derivative financial instruments as part of our price risk management program to protect our capital investments. We had net gains on derivative financial instruments of $51.7 million for 2019 and $10.0 million for 2020. Realized net gains from our oil and natural gas price risk management program were $52.7 million and $134.9 million in 2019 and 2020, respectively. Realized losses from our interest rate risk management program were none and $0.4 million in 2019 and 2020, respectively. Unrealized loss on derivative financial instruments were $1.0 million in 2019 and $124.5 million in 2020.
Interest expense. Interest expense was $234.8 million for 2020 as compared to $161.5 million for 2019. Interest expense for 2020 includes interest payments on the 7½% senior notes (the "2025 Notes") that were assumed in the Covey Park Acquisition, our 9¾% senior notes (the "2026 Notes") and our bank credit facility. Included in interest expense was amortization of the discount on the 2025 Notes, the 2026 Notes and the debt cost amortization associated with our outstanding debt. The non-cash interest expense for 2020 totaled $34.0 million compared with non-cash interest expense of $16.3 million for 2019. The increase in interest expense was due to the issuance of an additional $800.0 million principal amount of the 2026 Notes during 2020.
Income taxes. Income taxes were a benefit of $9.2 million in 2020 and a provision of $27.8 million in 2019. The effective tax rate of 22% in 2019 and 15% in 2020 differed from the federal income tax rate of 21% primarily due to the impact of deferred state income taxes.
Net income. We reported a net loss available to common stockholders of $83.4 million or $0.39 per share in 2020 and net income available to common stockholders of $74.5 million or $0.52 per diluted share in 2019. The net loss in 2020 is primarily due to the unrealized loss on derivative financial instruments of $124.5 million. Income from operations in 2020 was $163.0 million.
Year Ended December 31, 2019 Compared to 2018 Periods
Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report on Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the SEC on March 2, 2020.
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Liquidity and Capital Resources
Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or proceeds from asset sales. In 2020, we generated $575.7 million in cash flow from operating activities as compared to $451.2 million in 2019. We also completed a public offering of our common stock in which we received $196.5 million in net proceeds. The proceeds from the offering were used together with cash on hand to redeem our Series A Convertible Preferred Stock for $210.0 million. We also issued $800.0 million principal amount of our 9¾% senior notes for net proceeds of $737.1 million. The proceeds from the senior note issuances were used to repay outstanding borrowings under our bank credit facility. In addition in 2020, we exchanged 767,096 shares of our common stock, valued at approximately $5.0 million, to retire $5.6 million aggregate principal amount of our 7½% senior notes.
For 2019 our primary source of funds was operating cash flow and the issuance of common stock, preferred stock and borrowings to finance two acquisitions.
Our capital expenditure activity is summarized in the following table:
Predecessor Successor
Period from
January 1, 2018
through
August 13, 2018 Period from
August 14, 2018
through
December 31, 2018 Year Ended
December 31, 2019 Year Ended
December 31, 2020
(in thousands)
Acquisitions $ 39,323 $ 21,013 $ 2,097,451 $ —
Exploration and development:
Exploratory leasehold costs — — — 7,949
Development leasehold costs 2,848 1,715 7,603 13,022
Development drilling and completion costs 90,840 148,745 493,625 436,074
Other development costs 13,871 13,612 9,339 34,525
Total exploration and development 146,882 185,085 2,608,018 491,570
Other 31 2 198 366
Total capital expenditures $ 146,913 $ 185,087 $ 2,608,216 $ 491,936
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Under our current operating plan, we expect to drill 62 operated horizontal wells (51.0 net), and complete an additional 19 wells (17.4 net) drilled in 2020. We currently expect to spend approximately $517.0 million to $560.0 million in 2021 on our development and exploration projects. We expect to fund our future development and exploration activities with future operating cash flow. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including additional equity or debt financings. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
We do not have a specific acquisition budget for 2021 because the timing and size of acquisitions are unpredictable. We intend to use our cash flows from operations, borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.
As of December 31, 2020, we had $500.0 million outstanding under our bank credit facility that matures on July 16, 2024. The borrowing base, which is currently set at $1.4 billion, is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of our assets and those of our subsidiaries and bear interest at our option, at either LIBOR plus 2.25% to 3.25% or a base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a
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commitment fee of 0.375% to 0.5% on the unused portion of the borrowing base. The bank credit facility places certain restrictions upon our and our subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of December 31, 2020.
The following table summarizes our aggregate liabilities and commitments by year of maturity:
2021 2022 2023 2024 2025 Thereafter Total
(In thousands)
Bank credit facility $ — $ — $ — $ 500,000 $ — $ — $ 500,000
7½% Senior Notes due 2025 — — — — 619,400 — 619,400
9¾% Senior Notes due 2026 — — — — — 1,650,000 1,650,000
Interest 220,630 220,630 220,630 214,534 178,296 100,547 1,155,267
Operating leases 2,682 795 196 — — — 3,673
Transportation 21,517 31,208 24,820 24,888 24,820 144,783 272,036
Drilling rigs and completion 6,031 — — — — — 6,031
$ 250,860 $ 252,633 $ 245,646 $ 739,422 $ 822,516 $ 1,895,330 $ 4,206,407
Future interest costs are based upon the effective interest rates of our outstanding senior notes and borrowings under our bank credit facility.
We also have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties which are currently estimated to be incurred primarily after 2023.
Federal and State Taxation
The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January l, 2018 from 35% to 21%. Among the other significant tax law changes that potentially affect us 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 us 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, we completed the accounting for the tax effects of enactment of the Tax Cuts and Jobs Act.
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. Due to tax law enacted in 2020 with the Coronavirus Aid, Relief and Economic Security ("CARES") Act, we received $10.2 million in refunds for our outstanding AMT carryforwards in 2020.
At December 31, 2020, we had $0.9 billion in U.S. federal net operating loss carryforwards and $1.6 billion in certain state net operating loss carryforwards. 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, our ability to use net operating losses ("NOLs") to reduce taxable income is generally limited to an annual amount based on the fair market value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate. Our 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 our common stock immediately prior to the ownership change, we believe that we have a net unrealized built-in gain which will increase the Section 382 limitation during the five-year recognition period from 2018 to 2023.
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NOLs that exceed the Section 382 limitation in any year continue to be allowed as carryforwards 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. NOLs generated in 2018 and after would be carried forward indefinitely. Our use of new NOLs arising after the date of an ownership change would not be affected by the 382 limitation. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $844.6 million of the U.S. federal NOL carryforwards and $1.4 billion of the estimated state NOL carryforwards will expire unused.
Our federal income tax returns for the years subsequent to December 31, 2016 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2017. We currently believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.
Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.
Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities and timing of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.
Impairment of oil and gas properties. We evaluate our proved properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property's proved and risk adjusted probable oil and natural gas
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reserves estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. 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 the average first day of the month historical price for the year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of our oil and gas leases. It is reasonably possible that our 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 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 proved and unproved oil and gas properties in the future.
Goodwill. We have goodwill of $335.9 million as of December 31, 2020 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. We are not required to amortize goodwill as a charge to earnings; however, we are required to conduct an annual review of goodwill for impairment.
We determine the potential for impairment of our goodwill by initially preparing a qualitative fair value assessment of our business value. In performing this qualitative assessment, we examine relevant events and circumstances that could have a negative effect on our 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 our business is impaired, a quantitative analysis would be performed to assess our 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 market approach or an income approach. 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 our market capitalization declines, it is reasonably possible that impairments would need to be recognized. We performed a quantitative assessment of goodwill as of October 1, 2020 and determined there was no goodwill impairment.
Income Taxes. We account 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 future tax consequences attributable to the future utilization of existing tax net operating loss and other types of 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.
In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our 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. We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized. As a result, we established valuation allowances for our 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. We will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future reporting periods.
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Stock-based compensation. We follow 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.
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. We implemented ASU 2017-04 during the fourth quarter of 2020 when we performed the annual goodwill impairment assessment and it did not have a significant effect on our results of operations, liquidity or financial position.
In June 2016, The FASB issued Accounting Standards Update ASU No. 2016-13 ("ASU 2016-13") that amends guidance on reporting credit losses for trade receivables, net investments in leases, debt securities, loans and certain other instruments. ASU 2016-13 requires the use of a forward-looking expected loss model as opposed to existing incurred loss recognition. The guidance requires a cumulative-effect adjustment to the statement of financial position as of the beginning of the first reporting period in which the standard is effective. We implemented ASU 2016-13 during the first quarter of 2020. We concluded there was no cumulative-effect adjustment required and the other provisions of the standard did not have a significant effect on our results of operations, liquidity or financial position.