SILVERBOW RESOURCES, INC. (Form: 10-Q, Received: 05/06/2021 16:09:28)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X) Quarterly Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2021

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


Delaware			20-3940661
(State of Incorporation)			(I.R.S. Employer Identification No.)

575 North Dairy Ashford, Suite 1200

Houston, Texas 77079

(281) 874-2700

(Address and telephone number of principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	SBOW	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Yes			þ			No			o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).


Yes			þ			No			o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.


o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Yes			o			No			þ

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.


Yes			þ			No			o

Indicate the number of shares outstanding of each of the issuer’s classes

of common stock, as of the latest practicable date.


Common Stock ($.01 Par Value) (Class of Stock)			12,196,498 Shares outstanding at April 30, 2021

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2021

INDEX


		Page
Part I	FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements

	Condensed Consolidated Balance Sheets	4

	Condensed Consolidated Statements of Operations	5

	Condensed Consolidated Statements of Stockholders’ Equity	6

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 4.	Controls and Procedures	35

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Mine Safety Disclosures	36
Item 5.	Other Information	36
Item 6.	Exhibits	36

SIGNATURES		38

Table of Contents

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)


	March 31, 2021		December 31, 2020

ASSETS
Current Assets:
Cash and cash equivalents	$	3,419	$	2,118
Accounts receivable, net	26,075		25,850
Fair value of commodity derivatives	1,958		4,821

Other current assets	2,388		2,184
Total Current Assets	33,840		34,973
Property and Equipment:
Property and equipment, full cost method, including $29,113 and $28,090, respectively, of unproved property costs not being amortized at the end of each period	1,375,961		1,343,373
Less – Accumulated depreciation, depletion, amortization & impairment	(814,691)		(801,279)
Property and Equipment, Net	561,270		542,094
Right of Use Assets	3,409		4,366
Fair Value of Long-Term Commodity Derivatives	769		281

Other Long-Term Assets	1,162		1,421
Total Assets	$	600,450	$	583,135
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	20,601	$	26,991
Fair value of commodity derivatives	18,193		8,171
Accrued capital costs	6,611		7,324
Accrued interest	1,052		983
Current lease liability	2,292		3,473
Undistributed oil and gas revenues	26,416		11,098

Total Current Liabilities	75,165		58,040
Long-Term Debt, Net	395,172		424,905
Non-Current Lease Liability	1,126		951
Deferred Tax Liabilities	303		303
Asset Retirement Obligations	4,489		4,533
Fair Value of Long-Term Commodity Derivatives	3,869		2,946
Other Long-Term Liabilities	270		424
Commitments and Contingencies (Note 11)
Stockholders' Equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	—		—
Common stock, $0.01 par value, 40,000,000 shares authorized, 12,336,876 and 12,053,763 shares issued, respectively, and 12,159,615 and 11,936,679 shares outstanding, respectively	123		121
Additional paid-in capital	298,841		297,712
Treasury stock, held at cost, 177,261 and 117,084 shares, respectively	(2,860)		(2,372)
(Accumulated deficit) Retained earnings	(176,048)		(204,428)
Total Stockholders’ Equity	120,056		91,033
Total Liabilities and Stockholders’ Equity	$	600,450	$	583,135
See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Operations (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Revenues:
Oil and gas sales	$	86,741	$	53,377

Operating Expenses:
General and administrative, net	4,782		5,913
Depreciation, depletion, and amortization	13,393		23,439
Accretion of asset retirement obligations	75		86
Lease operating costs	6,274		5,812
Workovers	13		—
Transportation and gas processing	5,056		6,643
Severance and other taxes	3,489		2,964
Write-down of oil and gas properties	—		95,606
Total Operating Expenses	33,082		140,463

Operating Income (Loss)	53,659		(87,086)

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(18,259)		88,287
Interest expense, net	(7,019)		(8,407)
Other income (expense), net	(1)		107

Income (Loss) Before Income Taxes	28,380		(7,099)

Provision (Benefit) for Income Taxes	—		(1,241)

Net Income (Loss)	$	28,380	$	(5,858)

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	2.36	$	(0.50)

Diluted Earnings (Loss) Per Share	$	2.31	$	(0.50)

Weighted-Average Shares Outstanding - Basic	12,029		11,825

Weighted-Average Shares Outstanding - Diluted	12,294		11,825

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)


	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2019	$	119	$	292,916	$	(2,282)	$	104,954	$	395,707


Purchase of treasury shares (26,675 shares)	—		—		(83)		—		(83)

Issuance of restricted stock (105,108 shares)	1		(1)		—		—		—
Share-based compensation	—		1,335		—		—		1,335
Net Loss	—		—		—		(5,858)		(5,858)
Balance, March 31, 2020	$	120	$	294,250	$	(2,365)	$	99,096	$	391,101

Balance, December 31, 2020	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033


Purchase of treasury shares (60,177 shares)	—		—		(488)		—		(488)

Issuance of restricted stock (283,113 shares)	2		(2)		—		—		—
Share-based compensation	—		1,131		—		—		1,131
Net Income	—		—		—		28,380		28,380
Balance, March 31, 2021	$	123	$	298,841	$	(2,860)	$	(176,048)	$	120,056
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Cash Flows from Operating Activities:
Net income (loss)	$	28,380	$	(5,858)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	13,393		23,439
Write-down of oil and gas properties	—		95,606
Accretion of asset retirement obligations	75		86
Deferred income taxes	—		(1,065)
Share-based compensation	1,070		1,260
(Gain) Loss on derivatives, net	18,259		(88,287)
Cash settlement (paid) received on derivatives	(3,063)		47,650
Settlements of asset retirement obligations	(104)		(2)

Other	344		1,142
Change in operating assets and liabilities
(Increase) decrease in accounts receivable and other current assets	(878)		9,436
Increase (decrease) in accounts payable and accrued liabilities	10,301		(6,937)
Increase (decrease) in income taxes payable	—		(176)
Increase (decrease) in accrued interest	69		(211)
Net Cash Provided by (Used in) Operating Activities	67,846		76,083
Cash Flows from Investing Activities:
Additions to property and equipment	(35,852)		(52,618)
Acquisition of oil and gas properties	(205)		—

Payments on property sale obligations	—		(142)


Net Cash Provided by (Used in) Investing Activities	(36,057)		(52,760)
Cash Flows from Financing Activities:

Proceeds from bank borrowings	57,000		50,000
Payments of bank borrowings	(87,000)		(39,000)

Purchase of treasury shares	(488)		(83)

Net Cash Provided by (Used in) Financing Activities	(30,488)		10,917
Net Increase (Decrease) in Cash and Cash Equivalents	1,301		34,240
Cash and Cash Equivalents at Beginning of Period	2,118		1,358
Cash and Cash Equivalents at End of Period	$	3,419	$	35,598
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	6,424	$	8,048

Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	(3,588)	$	(1,989)

See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1) General Information

SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.

The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

(2) Summary of Significant Accounting Policies

Basis of Presentation. The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.

Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow 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 condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed 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 2020, 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. Crude oil prices fell further in April 2020, trading slightly higher in the third quarter of 2020 and continuing to improve in the fourth quarter of 2020. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021.

In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, 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 volumes as of December 31, 2020.

As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence is required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.

In addition, if the volatile pricing environment continues for an extended period or prices substantially decline, 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 6.

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Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Effective April 16, 2021, the Company entered into the Seventh Amendment to its First Amended and Restated Senior Secured Revolving Credit Agreement (as defined below), in conjunction with our regularly scheduled borrowing base redetermination. The Seventh Amendment redetermined the borrowing base of our Credit Facility (as defined below) from $310 million to $300 million and extended the maturity date from April 19, 2022 to April 19, 2024. See Note 6 for more information on the Seventh Amendment and its modifications to the Credit Facility.

Through April 30, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after March 31, 2021:


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)(1)	Weighted-Average Price
2021 Contracts
2Q21 (2)	6,000	$	61.46
2023 Contracts
1Q23	81,900	$	55.70

(1) Bbl refers to one barrel of oil.

(2) Transaction for a swap purchase to reduce overall hedge position.


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Collar Contracts
2022 Contracts
2Q22	1,046,500	$	2.35	$	2.63
3Q22	966,000	$	2.40	$	2.62
4Q22	864,800	$	2.45	$	2.83
2023 Contracts
1Q23	2,160,000	$	2.60	$	3.06

Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements)

Total Volumes
(MMBtu)

Weighted-Average Price

2022 Contracts

1Q22

1,800,000

0.13

There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.

Use of Estimates. The preparation of financial statements in conformity with 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:

•the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,

•estimates related to the collectability of accounts receivable and the credit worthiness of our customers,

•estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,

•estimates of future costs to develop and produce reserves,

•accruals related to oil and gas sales, capital expenditures and lease operating expenses ("LOE"),

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•estimates in the calculation of share-based compensation expense,

•estimates of our ownership in properties prior to final division of interest determination,

•the estimated future cost and timing of asset retirement obligations,

•estimates made in our income tax calculations, including the valuation of our deferred tax assets,

•estimates in the calculation of the fair value of commodity derivative assets and liabilities,

•estimates in the assessment of current litigation claims against the Company,

•estimates in amounts due with respect to open state regulatory audits, and

•estimates on future lease obligations.

While we are not currently aware of any material revisions to any of our estimates, there will likely 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.

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.

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 both the three months ended March 31, 2021 and 2020, such internal costs when capitalized totaled $1.1 million. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).

The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):


	March 31, 2021		December 31, 2020
Property and Equipment
Proved oil and gas properties	$	1,341,385	$	1,310,008
Unproved oil and gas properties	29,113		28,090
Furniture, fixtures and other equipment	5,463		5,275
Less – Accumulated depreciation, depletion, amortization & impairment	(814,691)		(801,279)
Property and Equipment, Net	$	561,270	$	542,094

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 natural 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.

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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 quarterly 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.

Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $95.6 million for the three months ended March 31, 2020 on our oil and natural gas properties. There was no impairment for the three months ended March 31, 2021.

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 decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.

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 March 31, 2021 and December 31, 2020, 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 condensed consolidated balance sheets.

At March 31, 2021, our “Accounts receivable, net” balance included $22.8 million for oil and gas sales, $1.1 million due from joint interest owners, $1.8 million for severance tax credit receivables and $0.3 million for other receivables. 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.

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 condensed consolidated statements of operations. The amount of supervision fees charged for each of the three months ended March 31, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.2 million for both the three months ended March 31, 2021 and 2020, 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. 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 federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. The

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Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of March 31, 2021.

The Company’s effective tax rate was approximately 0.0% and 17.5% for the three months ended March 31, 2021 and 2020, respectively. The difference in the Company’s effective tax rate and the statutory rate for the three months ended March 31, 2021 related to the movement in the valuation allowance against the Company's net deferred tax assets. The Company recorded an income tax benefit of $1.2 million for the three months ended March 31, 2020.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

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. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity.

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.

The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended March 31, 2021 and 2020 (in thousands):


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Oil, natural gas and NGLs sales:
Oil	$	17,466	$	18,050
Natural gas	62,914		31,472
NGLs	6,361		3,855
Total	$	86,741	$	53,377

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):


	March 31, 2021		December 31, 2020
Trade accounts payable	$	8,706	$	15,930
Accrued operating expenses	3,140		2,491
Accrued compensation costs	1,669		3,771
Asset retirement obligations – current portion	456		441
Accrued non-income based taxes	2,931		1,819
Accrued corporate and legal fees	153		150
Other payables	3,546		2,389
Total accounts payable and accrued liabilities	$	20,601	$	26,991

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the three months ended March 31, 2021, we purchased 60,177 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

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(3) Leases

The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 on January 1, 2019, using the modified retrospective transition approach. The Company elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2021, all of the Company’s leases were operating leases.

The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.

Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
Property, plant and equipment acquisitions - short-term leases	$	329	$	2,184
Property, plant and equipment acquisitions - operating leases	—		5
Total lease costs in property, plant and equipment additions	$	329	$	2,189


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Lease Costs Included in the Condensed Consolidated Statements of Operations
Lease operating costs - short-term leases	$	467	$	250
Lease operating costs - operating leases	1,165		1,437
General and administrative, net - operating leases	172		180
Total lease cost expensed	$	1,804	$	1,867

The lease term and the discount rate related to the Company's leases are as follows:


	March 31, 2021
Weighted-average remaining lease term (in years)	2.4
Weighted-average discount rate	4.1	%

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As of March 31, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):


	As of March 31, 2021
2021 (Remaining)	$	2,101
2022	948
2023	213
2024	41
2025	41
Thereafter	271
Total undiscounted lease payments	3,615
Present value adjustment	(197)
Net operating lease liabilities	$	3,418

Supplemental cash flow information related to leases was as follows (in thousands):


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,335	$	1,615
Investing cash flows from operating leases	$	—	$	5

(4) Share-Based Compensation

Share-Based Compensation Plans

In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.

The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.1 million and $1.2 million for the three months ended March 31, 2021 and 2020, respectively. Capitalized share-based compensation was less than $0.1 million and $0.1 million for the three months ended March 31, 2021 and 2020, respectively.

We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.

Stock Option Awards

The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.

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At March 31, 2021, we had $0.5 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2021:


	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	303,705	$	27.73


Options forfeited	(3,896)	$	16.96

Options outstanding, end of period	299,809	$	27.74
Options exercisable, end of period	250,750	$	28.03

Our outstanding stock option awards had no measurable aggregate intrinsic value at March 31, 2021. At March 31, 2021, the weighted-average remaining contract life of stock option awards outstanding was 4.5 years and exercisable was 4.2 years. The total intrinsic value of stock option awards exercisable had no value for the three months ended March 31, 2021.

Restricted Stock Units

The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).

As of March 31, 2021, we had $2.5 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 1.2 years.

The following table provides information regarding RSU activity for the three months ended March 31, 2021:


	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	574,916	$	9.02
RSUs granted	100,178	$	8.33


RSUs forfeited	(17,802)	$	11.09
RSUs vested	(259,313)	$	10.01
RSUs outstanding, end of period	397,979	$	8.10

Performance-Based Stock Units

On February 20, 2018, the Company granted 30,700 performance share units for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.

On May 21, 2019, the Company granted 99,500 performance-based stock units for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three years.

On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years.

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As of March 31, 2021, we had $2.7 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.5 years while 23,800 shares vested during the three months ended March 31, 2021.

(5) Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2021 and 2020 are discussed below.

The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):


	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	28,380	12,029	$	2.36	$	(5,858)	11,825	$	(0.50)
Dilutive Securities:

RSU Awards			265					—

Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	28,380	12,294	$	2.31	$	(5,858)	11,825	$	(0.50)

Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2020 because they were antidilutive due to the net loss.

Approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive while 0.3 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2020, because they were antidilutive due to the net loss.

Approximately 0.1 million shares of PSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive while approximately 0.1 million shares of PSUs were not included for the three months ended March 31, 2020 because they were antidilutive due to the net loss.

Approximately 2.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for the three months ended March 31, 2020 because these warrants were antidilutive. There were no warrants to purchase common stock for the three months ended March 31, 2021 as the warrants expired.

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(6) Long-Term Debt

The Company's long-term debt consisted of the following (in thousands):


	March 31, 2021		December 31, 2020
Credit Facility Borrowings (1)	$	200,000	$	230,000
Second Lien Notes due 2024	200,000		200,000
	400,000		430,000
Unamortized discount on Second Lien Notes due 2024	(1,227)		(1,295)
Unamortized debt issuance cost on Second Lien Notes due 2024	(3,601)		(3,800)
Long-Term Debt, net	$	395,172	$	424,905

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of March 31, 2021 and December 31, 2020, we had $1.1 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $200.0 million and $230.0 million as of March 31, 2021 and December 31, 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Seventh Amendment to the Credit Facility, effective April 16, 2021 (the “Seventh Amendment”), which among other things, redetermined the borrowing base under the Credit Facility to $300 million (from $310 million), including to (i) extend the maturity of our Credit Facility from April 19, 2022 to April 19, 2024; (ii) increase the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iii) reduce the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (iv) implement a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (v) increase the mortgage coverage and title requirements from 85% to 90%.

The Credit Facility provides for a maximum credit amount of $600.0 million, subject to the current borrowing base of $300.0 million as of April 16, 2021. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Effective April 16, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Company is currently evaluating the potential impact of eventual replacement of the LIBOR interest rate, and the Credit Agreement provides for options in the event LIBOR is discontinued.

The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 90% of estimated proved reserves of the Company and its subsidiary.

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The Credit Agreement contains the following financial covenants:

•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.0 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; and

•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.

As of March 31, 2021, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.

Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $2.5 million and $3.5 million for the three months ended March 31, 2021 and 2020, respectively.

There was no capitalized interest on our unproved properties for both the three months ended March 31, 2021 and 2020, respectively.

Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024.

Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.

The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.

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The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.

The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of March 31, 2021, the Company was in compliance with all financial covenants under the Second Lien.

The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.

As of March 31, 2021, total net amounts recorded for the Second Lien were $195.2 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.5 million and $4.9 million for the three months ended March 31, 2021 and 2020, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

(7) Acquisitions and Dispositions

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, no amount and $0.1 million was paid during the three months ended March 31, 2021 and 2020, respectively. The remaining obligation under this contract is $1.6 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of March 31, 2021 and December 31, 2020.

(8) Price-Risk Management Activities

Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.

During the three months ended March 31, 2021 and 2020, the Company recorded losses of $18.3 million and gains of $88.3 million, respectively, on its commodity derivatives. The Company made cash payments of $3.1 million and collected cash payments of $47.7 million for settled derivative contracts during the three months ended March 31, 2021 and 2020, respectively. Included in our collected cash payments during the three months ended March 31, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020.

At March 31, 2021, there were $0.4 million in receivables for settled derivatives while at December 31, 2020, we had $0.8 million in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in April 2021 and January 2021, respectively. At March 31, 2021 and December 31, 2020, we also had $2.3 million and $0.8 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in April 2021 and January 2021, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At March 31, 2021, there

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was $2.0 million and $0.8 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $18.2 million and $3.9 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2020, there was $4.8 million and $0.3 million in current and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 million in current and long-term unsettled derivative liabilities, respectively.

The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $19.3 million net fair value liability at March 31, 2021, and an $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2021:


Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2021 Contracts
2Q21	144,596	$	51.48
3Q21	179,759	$	51.19
4Q21	191,412	$	53.60
2022 Contracts
1Q22	178,455	$	45.77
2Q22	91,000	$	54.00
3Q22	200,100	$	47.05
4Q22	138,000	$	53.20
Collar Contracts
2021 Contracts
2Q21	116,980			$	34.33	$	40.30
3Q21	90,620			$	34.34	$	39.87
4Q21	84,640			$	34.70	$	41.01
2022 Contracts
1Q22	40,500			$	40.00	$	45.55
2Q22	115,850			$	39.25	$	46.20

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2021 Contracts
2Q21	832,255	$	2.41
3Q21	330,000	$	2.62
4Q21	290,000	$	2.69
2022 Contracts
3Q22	2,100	$	2.50
Collar Contracts
2021 Contracts
2Q21	7,731,000			$	2.39	$	2.77
3Q21	7,885,175			$	2.32	$	2.79
4Q21	7,151,000			$	2.50	$	2.87
2022 Contracts
1Q22	7,565,000			$	2.69	$	3.33
2Q22	4,200,000			$	2.10	$	2.60
3Q22	3,933,000			$	2.39	$	2.74
4Q22	3,680,276			$	2.40	$	2.89


Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2021 Contracts
2Q21	10,010,000	$	(0.02)
3Q21	10,120,000	$	(0.02)
4Q21	10,120,000	$	(0.02)
2022 Contracts
1Q22	2,700,000	$	(0.06)
2Q22	2,730,000	$	(0.06)
3Q22	2,760,000	$	(0.06)
4Q22	2,760,000	$	(0.06)


Oil Basis Contracts (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (Bbls)	Weighted-Average Price
2021 Contracts
2Q21	329,150	$	1.22
3Q21	262,200	$	1.27
4Q21	241,500	$	1.28
Calendar Monthly Roll Differential Swaps
2021 Contracts
2Q21	313,900	$	(0.37)
3Q21	253,000	$	(0.34)
4Q21	241,500	$	(0.33)
2022 Contracts
1Q22	180,000	$	0.03
2Q22	182,000	$	0.03
3Q22	184,000	$	0.03
4Q22	184,000	$	0.03

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NGL Contracts	Total Volumes (Bbls)	Weighted-Average Price
2021 Contracts
2Q21	144,733	$	24.13
3Q21	146,324	$	24.13
4Q21	146,324	$	24.13

(9) Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below).

The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).

The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):

Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.

Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.

Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2021 and December 31, 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.


	Fair Value Measurements at
(in millions)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 31, 2021
Assets
Natural Gas Derivatives	$	1.6	$	—	$	1.6	$	—
Natural Gas Basis Derivatives	$	0.1	$	—	$	0.1	$	—
Oil Derivatives	$	1.0	$	—	$	1.0	$	—


Liabilities
Natural Gas Derivatives	$	3.9	$	—	$	3.9	$	—
Natural Gas Basis Derivatives	$	2.0	$	—	$	2.0	$	—
Oil Derivatives	$	13.7	$	—	$	13.7	$	—
Oil Basis Derivatives	$	1.0	$	—	$	1.0	$	—
NGL Derivatives	$	1.5	$	—	$	1.5	$	—
December 31, 2020
Assets
Natural Gas Derivatives	$	1.5	$	—	$	1.5	$	—
Natural Gas Basis Derivatives	$	1.1	$	—	$	1.1	$	—
Oil Derivatives	$	2.5	$	—	$	2.5	$	—

Liabilities
Natural Gas Derivatives	$	4.0	$	—	$	4.0	$	—
Natural Gas Basis Derivatives	$	0.4	$	—	$	0.4	$	—
Oil Derivatives	$	5.9	$	—	$	5.9	$	—
Oil Basis Derivatives	$	0.8	$	—	$	0.8	$	—

Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.

(10) Asset Retirement Obligations

Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs upon initial recording, excluding salvage values.

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The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2020 and the three months ended March 31, 2021 (in thousands):


Asset Retirement Obligations as of December 31, 2019	$	4,447
Accretion expense	354
Liabilities incurred for new wells and facilities construction	281

Reductions due to plugged wells and facilities	(103)
Revisions in estimates	(5)
Asset Retirement Obligations as of December 31, 2020	$	4,974
Accretion expense	75
Liabilities incurred for new wells and facilities construction	154

Reductions due to plugged wells and facilities	(101)
Revisions in estimates	(157)
Asset Retirement Obligations as of March 31, 2021	$	4,945

At March 31, 2021 and December 31, 2020, approximately $0.5 million and $0.4 million, respectively, of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

(11) Commitments and Contingencies

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 32 of this report.

Company Overview

SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where it has assembled approximately 130,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.

Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

Outlook and Business Plan Update

In February 2021, Winter Storm Uri brought extreme cold weather, ice and snow across Texas, Oklahoma and much of the southern region of the United States. This resulted in unplanned industry interruptions to oil and gas operations and a brief spike in natural gas spot prices. On February 17, 2021, the Henry Hub spot price for natural gas closed at $23.86 per MMBtu, compared to the January 2021 monthly average price of $2.71 per MMBtu. For SilverBow, the extreme cold weather resulted in approximately six days of lower production; however, the resiliency of the Company's operations also provided the opportunity to execute natural gas sales at favorable prices, resulting in higher revenues than forecasted for February 2021. This led to a short period of increased labor and cost of buying back natural gas, resulting in partially offset operating expense increases. The duration of the extreme cold weather impact to SilverBow's operations was short, with production levels normalizing within the span of one week.

Oil prices for the first quarter of 2021 increased relative to the collapse in prices during 2020. First quarter 2021 prompt-month WTI prices averaged $58 per barrel compared to $46 per barrel for first quarter 2020. Core to the Company's business strategy is a well-balanced inventory of oil and gas locations and flexibility to adjust its drilling schedule and capital budget in real-time. As of May 6, 2021, SilverBow is reaffirming its capital budget for full year 2021 of $100-$110 million, with a higher allocation towards liquids-rich locations. SilverBow may, in alignment with prevailing commodity prices, strategic decisions and the pursuit of the highest return projects, adjust on an ongoing basis its 2021 capital budget and drilling and completion (“D&C”) activities which could result in an increase or decrease to its current guidance range.

Overall, the Company's strategy of procuring cost savings on D&C activities allows SilverBow to add activity and stay within its capital range. The Company plans to continue pursuing a single-basin operating model, focused on its low-cost structure and optionality across multiple commodity phase windows of the Eagle Ford. As a returns-focused operator, SilverBow employs a risk mitigation strategy by hedging forecasted production volumes and protecting cash flow.

As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence is required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except for the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.

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Operational Results

Total production for the three months ended March 31, 2021 decreased 22% from the three months ended March 31, 2020 to 180 million cubic feet of natural gas equivalent per day as SilverBow switched to a more moderated growth and lower capital spending strategy during the second quarter of 2020 carrying through the remainder of the year.

During the first quarter of 2021, the Company drilled one well and completed seven wells in its Webb County Gas area. Six of these completed wells comprised SilverBow's second La Mesa pad, which was drilled in fourth quarter of 2020. The pad’s total D&C costs came in 13%, or $5 million, below authorization for expenditure (“AFE”) and 15% below the Company’s first La Mesa pad. The cost efficiency gains were a result of further applied learnings from the first pad. The wells were brought online approximately 15 days ahead of schedule and achieved an average pad production rate of 84 million cubic feet per day (“MMcf/d”) over the first 30 days of production (“IP30”). Importantly, both La Mesa pads co-developed the upper and lower Eagle Ford, which supports SilverBow's understanding of constructive interference and minimal-to-no impact from offset well interference and parent-child well performance degradation. The efficiency gains from 2020 carried into the first quarter of 2021 with faster cycle times on the La Mesa pad and lower capital costs. These efficiencies ultimately provided SilverBow with both the time and capital to add the Webb County Austin Chalk test during the first quarter of 2021. The Company's Austin Chalk well achieved an IP30 of 13 MMcf/d, exceeding initial expectations and commercial criteria. Given the strong performance and competitive economics exhibited to date, SilverBow plans to drill additional Austin Chalk wells this year.

The extreme cold weather during February 2021 temporarily impacted first quarter production by approximately 2 million cubic feet of gas equivalent per day (“MMcfe/d”). SilverBow was able to mitigate the effect of the storm through numerous pre-planning procedures and existing storm response procedures in place. Per normal practice, the Company maintains a portion of its natural gas sales tied to daily gas indexes. Therefore, the Company did have some natural gas sales exposed to the unprecedented volatility in daily spot prices during the cold weather event in February 2021, resulting in unusually high realized natural gas prices in the first quarter of 2021. The impact of these factors on SilverBow's financial results for the first quarter of 2021 is not expected to recur at this magnitude in future quarters. Notably, the Company continues to operate at a zero total recordable incident rate (“TRIR”) despite the weather events in the field.

Scheduled maintenance projects during the first quarter of 2021 resulted in a slight increase to lease operating expenses (“LOE”). Additionally, measures taken to prepare for and recover from the storm resulted in higher than typical expenses. For the first quarter of 2021, the Company offset minor service pricing increases in its D&C activities. On the drilling side, SilverBow has been able to hold service costs flat based on close vendor relationships and existing contracts. On the completions side, costs remain mostly flat as service price inflation has primarily been offset through continued de-bundling of sand and other logistics and consumables. Additionally, the Company has been able to lower facility hookup costs per well by $40,000 on average through improved design processes and utilizing vendors with greater scale and volume discounting.

2021 Cost Reduction Initiatives: SilverBow continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's LOE and workover expenses were $6.3 million or $0.39 per thousand cubic feet of gas equivalent (“Mcfe”) for the first three months of 2021, as compared to $5.8 million or $0.28 per Mcfe for the same period in 2020. The increase in costs is due to incremental expenses related to Winter Storm Uri, higher utilities and higher compression costs. These increases were partially mitigated by lower chemical, treating and salt water disposal costs. The increase in LOE on a per Mcfe basis is due to the lower production volumes.

SilverBow's net general and administrative (“G&A”) costs were $4.8 million, or $0.29 per Mcfe, and cash G&A costs were $3.7 million (a non-GAAP financial measure calculated as net G&A costs less $1.1 million of share-based compensation), or $0.23 per Mcfe, for the first three months of 2021, compared to net G&A costs of $5.9 million, or $0.28 per Mcfe, and cash G&A costs of $4.6 million (a non-GAAP financial measure calculated as net G&A costs less $1.3 million of share-based compensation), or $0.22 per Mcfe, for the three months ended March 31, 2020.

SilverBow Resources reports cash G&A because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, the Company believes cash G&A expenses are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based

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compensation programs which can vary substantially from company to company. Cash G&A expenses should not be considered as an alternative to, or more meaningful than, total net G&A expenses.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties and to repay Credit Facility borrowings. As of March 31, 2021, the Company’s liquidity consisted of $3.4 million of cash-on-hand and $110.0 million in available borrowings on its Credit Facility, which had a $310 million borrowing base. In conjunction with its regularly scheduled semi-annual redetermination, SilverBow entered into the Seventh Amendment, effective April 16, 2021, which among other things, redetermined the borrowing base under the Credit Facility to $300 million and extended the maturity date to April 19, 2024. As of April 30, 2021, we had $90 million in available borrowings under the Credit Facility. Management believes the Company has sufficient liquidity to meet its obligations through the second quarter of 2022 and execute its long-term development plans. For more details, see the Subsequent Events section within Note 2 and the Credit Facility section within Note 6 to SilverBow's condensed consolidated financial statements for more information on its Credit Facility.

Contractual Commitments and Obligations

There were no other material changes in SilverBow's contractual commitments during the three months ended March 31, 2021 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2020.

Off-Balance Sheet Arrangements

As of March 31, 2021, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.

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Summary of 2021 Financial Results Through March 31, 2021

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $86.7 million for the three months ended March 31, 2021, compared to $53.4 million for the three months ended March 31, 2020. Revenues were higher primarily due to overall higher commodity pricing primarily as a result of the extreme cold weather in February 2021. The Company's net income was $28.4 million for the three months ended March 31, 2021, compared to a net loss of $5.9 million for the three months ended March 31, 2020. The increase in net income was primarily due to higher revenues for the three months ended March 31, 2021.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $33.0 million for the three months ended March 31, 2021 compared to $50.7 million for the three months ended March 31, 2020. The expenditures for the three months ended March 31, 2021 and 2020 were attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of $41.3 million at March 31, 2021 and a working capital deficit of $23.1 million at December 31, 2020. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the three months ended March 31, 2021, the Company generated cash from operating activities of $67.8 million, of which $9.5 million was attributable to changes in working capital. Cash used for property additions was $35.9 million. This included $3.6 million attributable to a net decrease of capital-related payables and accrued costs. The Company’s net repayments on the Credit Facility were $30.0 million during the three months ended March 31, 2021.

For the three months ended March 31, 2020, the Company generated cash from operating activities of $76.1 million, of which $2.1 million was attributable to changes in working capital. Cash used for property additions was $52.6 million. This included $2.0 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.1 million was paid during the three months ended March 31, 2020 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the Credit Facility were $11.0 million during the three months ended March 31, 2020.

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Results of Operations

Revenues — Three Months Ended March 31, 2021 and Three Months Ended March 31, 2020

Natural gas production was 78% and 79% of the Company's production volumes for the three months ended March 31, 2021 and 2020, respectively. Natural gas sales were 73% and 59% of oil and gas sales for the three months ended March 31, 2021 and 2020, respectively.

Crude oil production was 12% of the Company's production volumes for both the three months ended March 31, 2021 and 2020. Crude oil sales were 20% and 34% of oil and gas sales for the three months ended March 31, 2021 and 2020, respectively.

NGL production was 10% and 9% of the Company's production volumes for the three months ended March 31, 2021 and 2020, respectively. NGL sales were 7% of oil and gas sales for both the three months ended March 31, 2021 and 2020.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended March 31, 2021 and 2020:


Fields	Three Months Ended March 31, 2021			Three Months Ended March 31, 2020
	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)
Artesia Wells	$	14.5	3,252	$	14.3	4,342
AWP	17.0		2,715	13.3		3,024
Fasken	33.1		6,800	18.4		9,665
Other (1)	22.1		3,457	7.4		3,744
Total	$	86.7	16,224	$	53.4	20,775

(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.

The sales volumes decrease from 2020 to 2021 was primarily due to decreased production as a result of shut-in production volumes related to the extreme cold weather in February 2021.

In the first quarter of 2021, our $33.4 million, or 63%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $45.0 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately $11.6 million unfavorable impact on sales due to overall decreased commodity production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended March 31, 2021 and 2020 (in thousands, except per-dollar amounts):


	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Production volumes:
Oil (MBbl) (1)	315		401
Natural gas (MMcf)	12,624		16,498
Natural gas liquids (MBbl) (1)	285		312
Total (MMcfe)	16,224		20,775

Oil, natural gas and natural gas liquids sales:
Oil	$	17,466	$	18,050
Natural gas	62,914		31,472
Natural gas liquids	6,361		3,855
Total	$	86,741	$	53,377

Average realized price:
Oil (per Bbl)	$	55.49	$	45.05
Natural gas (per Mcf)	4.98		1.91
Natural gas liquids (per Bbl)	22.30		12.35
Average per Mcfe	$	5.35	$	2.57

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(12.75)	$	11.09
Natural gas (per Mcf)	(0.01)		0.50
Natural gas liquids (per Bbl)	(2.07)		—
Average per Mcfe	$	(0.29)	$	0.61

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	42.74	$	56.15
Natural gas (per Mcf)	4.97		2.40
Natural gas liquids (per Bbl)	20.23		12.35
Average per Mcfe	$	5.06	$	3.18

(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.

For the three months ended March 31, 2021 and 2020, the Company recorded net losses of $18.3 million and net gains of $88.3 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended March 31, 2021 and Three Months Ended March 31, 2020

The following table provides additional information regarding our expenses for the three months ended March 31, 2021 and 2020:


Costs and Expenses	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
General and administrative, net	$	4,782	$	5,913
Depreciation, depletion, and amortization	13,393		23,439
Accretion of asset retirement obligations	75		86
Lease operating cost	6,274		5,812
Workovers	13		—
Transportation and gas processing	5,056		6,643
Severance and other taxes	3,489		2,964
Interest expense, net	7,019		8,407
Write-down of oil and gas properties	—		95,606

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.29 and $0.28 for the three months ended March 31, 2021 and 2020, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens, lower share-based compensation and lower temporary labor fees. Included in general and administrative expenses is $1.1 million and $1.2 million in share-based compensation for the three months ended March 31, 2021 and 2020, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.83 and $1.13 for the three months ended March 31, 2021 and 2020, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs in the previous year.

Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.39 and $0.28 for the three months ended March 31, 2021 and 2020, respectively. The increase per Mcfe was due to lower production. The increase in costs is due to higher compression and utility costs, partially offset by lower chemical, treating and salt water disposal costs.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.31 and $0.32 for the three months ended March 31, 2021 and 2020, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.22 and $0.14 for the three months ended March 31, 2021 and 2020, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.0% and 5.6% for the three months ended March 31, 2021 and 2020, respectively.

Interest. Our gross interest cost was $7.0 million and $8.4 million for the three months ended March 31, 2021 and 2020, respectively. The decrease in gross interest cost is primarily due to decreased borrowings and lower interest rates. There were no capitalized interest costs for the three months ended March 31, 2021 or 2020.

Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the three months ended March 31, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $95.6 million on our oil and natural gas properties. There was no impairment for the three months ended March 31, 2021.

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Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our 2020 Annual Report on Form 10-K.

Forward-Looking Statements

This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on current expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, including those regarding our strategy, future operations, financial position, well expectations and drilling plans, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry;

• actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;

• shut-in and curtailment of production due to decreases in available storage capacity or other factors;

• volatility in natural gas, oil and NGL prices;

• future cash flows and their adequacy to maintain our ongoing operations;

• liquidity, including our ability to satisfy our short- or long-term liquidity needs;

• our borrowing capacity and future covenant compliance;

• operating results;

• asset disposition efforts or the timing or outcome thereof;

• ongoing and prospective joint ventures, their structures and substance, and the likelihood of their finalization or the timing thereof;

• the amount, nature and timing of capital expenditures, including future development costs;

• timing, cost and amount of future production of oil and natural gas;

• availability of drilling and production equipment or availability of oil field labor;

• availability, cost and terms of capital;

• timing and successful drilling and completion of wells;

• availability and cost for transportation of oil and natural gas;

• costs of exploiting and developing our properties and conducting other operations;

• competition in the oil and natural gas industry;

• general economic conditions;

• opportunities to monetize assets;

• our ability to execute on strategic initiatives;

• effectiveness of our risk management activities including hedging strategy;

• environmental liabilities;

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• counterparty credit risk;

• governmental regulation and taxation of the oil and natural gas industry;

• developments in world oil and natural gas markets and in oil and natural gas-producing countries;

• uncertainty regarding our future operating results; and

• other risks and uncertainties described in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2020.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, except as required by law.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price swings in recent periods.

Our price risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.

Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and, when considered necessary, we also obtain letters of credit from certain customers, parent company guarantees if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Concentration of Sales Risk. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.

Interest Rate Risk. At March 31, 2021, we had a combined $400.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at March 31, 2021 would increase our annual interest expense by $4.0 million.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended March 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.

Item 1A. Risk Factors.

A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes in our risk factors disclosed in the 2020 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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Item 6. Exhibits.

The following exhibits in this index are required by Item 601 of Regulation S-K and are filed herewith or are incorporated herein by reference:


3.1			First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-087541).
3.2			First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
10.1+*			Form of Restricted Stock Unit Agreement – Non-Employee Directors 2021.
10.2+*			Form of Cash Incentive Award Agreement – Non-Employee Directors 2021.
10.3+*			Form of Performance Share Unit Agreement – Officers 2021.
10.4+*			Form of Cash Incentive Award Agreement – Officers 2021.
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Filed herewith

# Furnished herewith. Not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

+Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

SILVERBOW RESOURCES, INC.
(Registrant)

Date:

May 6, 2021

By:

/s/ Christopher M. Abundis

Christopher M. Abundis
Executive Vice President,
Chief Financial Officer,
General Counsel and Secretary

Date:

May 6, 2021

By:

/s/ W. Eric Schultz

W. Eric Schultz
Controller


Vest Date			Shares Vested
[VEST DATE]			[VEST AMOUNT]


Date			Portion of Cash Incentive Award Vested
[VEST DATE]			$[100% of Cash Incentive Award]


Participant:			[[FIRSTNAME]] [[MIDDLENAME]] [[LASTNAME]]
Date of Grant:			[GRANT DATE]
Award Type and Description:			Performance Award granted pursuant to Article X of the Plan. This Award represents the right to receive Shares in an amount up to 200% of the Target PSUs (defined below), subject to the terms and conditions set forth herein and in the Agreement. Your right to receive settlement of this Award in an amount ranging from 0% to 200% of the Target PSUs shall vest and become earned and nonforfeitable upon (i) your satisfaction of the continued employment or service requirements described below under “Service Requirement” and (ii) the Committee’s certification of the level of achievement of the Performance Goal (defined below). The portion of the Target PSUs actually earned upon satisfaction of the foregoing requirements is referred to herein as the “Earned PSUs.”
Target Number of PSUs:			[[SHARESGRANTED]] (the “Target PSUs”).
Performance Period:			[BEGIN DATE] through [END DATE] (the “Performance Period End Date”).
Service Requirement:			Except as expressly provided in Section 3 of the Agreement, you must remain continuously employed by, or continuously provide services to, the Company or an Affiliate, as applicable, from the Date of Grant through the Performance Period End Date to be eligible to receive payment of this Award, which payment is based on the level of achievement with respect to the Performance Goal (as defined below).
Performance Goal:			The “Performance Goal” for the Performance Period is based on the Company’s achievement with respect to relative total stockholder return, as described in Appendix B attached hereto.
Settlement:			Settlement of the Earned PSUs shall be made solely in Shares, which shall be delivered to you in accordance with Section 4 of the Agreement.


Performance Level	Relative TSR Performance (Percentile Rank vs. Peers)	Earned PSUs (% of Target)*
Below Threshold	Below 25th Percentile	0%
Threshold	≥ 25th Percentile	50%
Target	≥ 50th Percentile	100%
Stretch	≥ 90th Percentile	200%


Date			Portion of Cash Incentive Award Vested
[VEST DATE]			$[100% of Cash Incentive Award]


			PARTICIPANT [[SIGNATURE]]
			[[FIRSTNAME]] [[MIDDLENAME]] [[LASTNAME]]


Date:	May 6, 2021	/s/ Sean C. Woolverton
		Sean C. Woolverton Chief Executive Officer