Principles of Consolidation. The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

COVID-19. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In March, the spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020.

In April 2020, WTI oil prices declined further to approximately $10 per barrel for May 2020 delivery. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively, on June 30, 2020. Crude oil prices traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020. Crude oil prices continued to improve in the fourth quarter of 2020 with Brent and WTI crude closing at approximately $52 and $49 per barrel, respectively, on December 31, 2020.

In response to these market conditions, including the COVID-19 pandemic and the decline in oil prices and economic outlook, the Company released its sole drilling rig in April 2020, and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed oil volumes and a substantial portion of natural gas volumes. Approximately 20 million cubic feet per day (“MMcf/d”) of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October 2020 to align with favorable natural gas prices, with all previously shut-in volumes returned to production as of December 31, 2020.

The full impact of the COVID-19 pandemic continues to evolve as of the date of this report. As such, the full magnitude that the pandemic will have on the Company’s financial condition, liquidity, and future results of operations is uncertain. Management is actively monitoring the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and workforce.

In addition, if the depressed pricing environment continues for an extended period, it may in the future lead to (i) a further reduction in oil and natural gas reserves, including the possible further removal of proved undeveloped reserves (ii) further impairment of proved and/or unproved oil and natural gas properties and a potential increase in depletion expense and (iii) reductions in the borrowing base under the Credit Agreement as discussed in Note 4.

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On February 5, 2021, and in the ordinary course of business, the Company entered into a new five-year lease agreement for office space in Houston, Texas. The operating lease begins on May 18, 2021.


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)(1)	Weighted-Average Price
2021 Contracts
Swap Purchase Contracts
1Q21(2)	13,750	$	53.10
2Q21(2)	51,050	$	53.22
2022 Contracts
Swap Contracts
1Q22	45,000	$	50.00
2Q22	45,500	$	50.00
3Q22	46,000	$	50.00
4Q22	46,000	$	50.00


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2021 Contracts
2Q21	1,820,000	$	2.83	$	2.98
3Q21	1,850,000	$	2.88	$	3.09
4Q21	1,840,000	$	2.95	$	3.18
2022 Contracts
1Q22	3,150,000	$	2.95	$	3.31

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

While we are not currently aware of any material revisions to any of our estimates, there may be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years ended December 31, 2020 and 2019, such internal costs when capitalized totaled $3.5 million and $5.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 4 of these Notes to Consolidated Financial Statements for further discussion on capitalized interest costs).



	December 31, 2020		December 31, 2019
Property and Equipment
Proved oil and gas properties	$	1,310,008	$	1,201,296
Unproved oil and gas properties	28,090		41,201
Furniture, fixtures, and other equipment	5,275		5,220
Less – Accumulated depreciation, depletion, amortization & impairment	(801,279)		(380,728)
Property and Equipment, Net	$	542,094	$	866,989

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.

Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).

The calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was a $355.9 million ceiling test write-down for the year ended December 31, 2020. There was no write-down for the year ended December 31, 2019.

If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices remain depressed or continue to decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future

Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.

Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both December 31, 2020 and 2019, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.

At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables. At December 31, 2019, our “Accounts receivable, net” balance included $24.6 million for oil and gas sales, $3.7 million for joint interest owners, $5.4 million for severance tax credit receivables and $3.3 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2020 and 2019 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $4.4 million and $4.9 million for the years ended December 31, 2020 and 2019, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2020, we did not have any accrued liability for uncertain tax positions.

In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expense of $21.2 million through the second quarter of 2020. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company would more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance resulting in a net deferred

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. On December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021 (the “Appropriations Act”). The Appropriations Act funds the federal government to the end of the fiscal year and provides further COVID-19 economic relief, including expansion of the employee retention credit. The Company continues to examine the impact that the CARES Act and the Appropriations Act may have on its business but does not currently expect either to have a material effect on its financial condition, results of operation, or liquidity.


	December 31, 2020		December 31, 2019
Trade accounts payable	$	15,930	$	26,121
Accrued operating expenses	2,491		3,873
Accrued compensation costs	3,771		4,601
Asset retirement obligations – current portion	441		392
Accrued non-income based taxes	1,819		1,413
Accrued corporate and legal fees	150		109
Other payables	2,389		2,834
Total accounts payable and accrued liabilities	$	26,991	$	39,343

Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2020 and 2019, we purchased 28,731 and 22,482 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

New Accounting Pronouncements. In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make

the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements.

Leases. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019 using the modified retrospective transition approach with an effective date of January 1, 2019.